Connacher Oil and Gas mit weiter guten Aussichten - 500 Beiträge pro Seite

[Kostolany4]

Die gesicherten Reserven sind 311 Mio. Barrel Bitumen.
Die Marktkapitalisierung beträgt 560 Mio. Euro.

Aus der Homepage:
Connacher Oil and Gas Limited is a Calgary-based Canadian oil and natural gas exploration and production company. Its principal asset is a 100 percent interest in 107 sections (68,480 acres) of oil sands leases at its Great Divide oil sands project near Fort McMurray, Alberta. It also maintains conventional production at Battrum, Tompkins and Steelman, Saskatchewan. In pursuing its objective of maximizing shareholder value, when possible Connacher secures large, operated interests. Over time, a balanced portfolio of oil and natural gas interests is being pursued. An opportunistic approach, supported by timely decisions, reflects management`s experience and aggressive strategy towards realizing growth objectives. Connacher also owns 35 percent (book) of and manages Petrolifera Petroleum Limited, which has interests in Argentina and Peru.

Hier ein 2-Seiten-Profil incl. letzten Bilanzbericht:
http://www.connacheroil.com/documents/CLL-2005-Profile-12-15…

Jedenfalls eine 100% seriöse kanadische Ölsandcompany, die mit steigenden Ölpreisen weiter gut performen wird.

[bioperformer]

[posting]20.042.431 von Kostolany4 am 04.02.06 15:24:46[/posting]Ölsand ist zweifelsohne eine sehr interessante und möglicherweise auch sehr zukunftsträchtige Angelegenheit, die vielleicht noch sehr große Chancen birgt, bei der jedoch auch mittlerweile schon auch ein paar Dinge zu beachten sind - wie ich kürzlich erst lesen durfte.

Folgende Betrachtung ist nicht speziell für Connacher maßgeblich, sondern eher für den Gesamtbereich von Unternehmen die im Themenbereich Ölsand tätig sind, darauf wollte ich nur gleich im Vorab hinweisen.

Zunächst mal liegt die weitere Zukunft der in diesem Bereich tätigen Unternehmen vor allem in der weitern Entwicklung des Ölpreises.
Bleibt dieser konstant oder steigt er gar wird der Bereich Ölsand boomen und zweifelsfrei gute Gewinne einfahren. Bei vielleicht sogar sinkenden Ölpreisen - wohl eher unwahrscheinlich - jedoch dürften manche der hier wirtschaftenden Unternehmen möglicherweise sogar Probleme bekommen, da die Rentabilität erheblich absinkt. Die Kosten der Gewinnung sind hier wegen der entsprechend aufwändigen Verfahren erheblich und nur solange tragbar, wie ein gewisser Preis beim Rohöl nicht unterschritten wird. Danach könnte hier schnell das momentan hell leuchtende Licht verglühen.

Die zweite bekannt werdende Unsicherheit liegt im Investitionsbereich der hier bereits tätigen Firmen. Dieser soll gewaltig sein, da ist von Kosten in Milliardenhöhe die Rede - kein Wunder auch wenn man bedenkt was beispielsweise die hier zum Transport verwendeten Ladetrucks kosten. Von denen werden jedoch ganze Flotten benötigt um solche Mengen an Material bewegen zu können.

Rating-Agenturen haben mittlerweile damit begonnen hier tätige Unternehmen genauer zu durchleuchten und raten mittlerweile nach Ermittlung des schon genannten Kapitalbedarfes in diesem Sektor zum Untergewichten bei hier fälligen Investitionsentscheidungen großer Anleger.

Zudem sei die mittlerweile klare Struktur bei den Eigentumsverhältnissen in den Gebieten, die eine wirtschaftliche Förderung erlauben soweit fortgeschritten, daß es sozusagen keine bekannten Gebiete mehr gibt, welche noch vom einen oder anderen Unternehmen günstig erworben werden könnten.
Daraus folgern jene Rating-Agenturen daß nur noch teure Firmenübernahmen möglich seien wenn eine Betriebsvergrößerung bei einem schon bestehenden Unternehmen anstünde, und diese wiederum solle auf den bereits gängigen Kursniveaus für den Anleger kaum mehr großes Gewinnpotenzial beinhalten.

Leider habe ich momentan nicht konkret in Erinnerung in welchem Thread ich genau den zu diesem Thema passenden Artikel las, aber vielleicht bringt uns ja da noch jeman auf die richtige Fährte.

bio

[matahaari]

Front Page Edmonton Journal

U.S. eyeing Alberta oilsands

Sheldon Alberts
CanWest News Service

Saturday, February 04, 2006

CREDIT: Calgary Herald, CanWest News Service
An oil pump jack is silhouetted against the sunrise at the southeast outskirts of Calgary on Wednesday.

WASHINGTON -- The U.S. Department of Energy is predicting crude oil from Alberta`s oilsands -- not alternative energy sources such as biomass ethanol -- will help halve America`s dependence on overseas oil within two decades.

The assessment, in a report to be released later this month, follows President George W. Bush`s challenge this week for the U.S. to sharply reduce its oil imports from unstable nations in the Middle East.

According to data obtained by the Reuters news agency, the U.S. Energy Information Administration estimates America`s oil imports from Canada will almost double by 2025, from 1.6 million barrels a day to 2.7 million barrels a day.

The vast majority of that increased production will come from Alberta`s oilsands, which are expected to produce as much as three million barrels a day by 2020.

"If (the United States) receives it all, which we don`t have in our forecast, it could reduce even more our dependence on the Middle East," an energy department official told Reuters.

The U.S. predicts the surge in Canadian oil will be a major factor in slashing imports of Middle East oil from the current six million barrels a day to three million.

The news comes just days after Bush, in his annual State of the Union address, declared: "America is addicted to oil."

Bush said the U.S. must move "beyond a petroleum-based economy" and set a target of reducing 75 per cent of oil imports from the Middle East by 2025.

His prescription for reducing oil consumption ranged from sharply increased use of bio-based fuel, solar energy, cleaner coal plants and nuclear power.

But with many alternative fuels still years away from commercial viability, the White House and other U.S. lawmakers have also been increasingly eyeing Canada`s oil supplies as they search for more secure and stable energy sources.

In October, Utah Senator Orrin Hatch said Canada was poised to surpass Saudi Arabia as "the world`s oil giant" in the 21st century.

Alberta`s oilsands hold an estimated 175 billion barrels of recoverable oil, second only to Saudi Arabia in terms of overall reserves.

U.S. Vice-President Dick Cheney had planned to visit Fort McMurray -- the hub of Alberta`s oilsands production -- last September but postponed the trip because of the Hurricane Katrina crisis. Officials with the Canadian embassy in Washington say they are trying to reschedule the visit.

On Friday, Cheney stressed that Bush`s call for a shift away from oil would not mean any government-imposed solution to reduce consumption.

[wmuehli]

wird connacher oil & gas nicht auch von Michael Schaefer in USA als "Rentenversicherung" besprochen??

[XIO]

Bin auch drin.
Im kanadaboard ist ja voll die Vorfreude ausgebrochen.
http://www.stockhouse.ca/bullboards/forum.asp?StartDir=O&Sta…

[wmuehli]

ja scheint sich jetzt auszuzahlen, dass ich drin bin.

Hab schon gezweifelt, ob das richtig war, denn von da an gings bergab.

Time will tell, mal sehn, was das heute wird mit CLL !

[XIO]

16:12 EST Thursday, March 02, 2006
http://www.globeinvestor.com/servlet/WireFeedRedirect?cf=Glo…

Das kam gestern abend:
Holly Announces Sale of Montana Refinery Assets to Connacher
http://www.stockhouse.ca/news/news.asp?newsid=3461586&tick=C…



Dazu Insiderkäufe:
Feb 24/06 Feb 23/06 Marston, Stephen Adair 11 - Acquisition carried out privately Common Shares 10,000 $5.250
Feb 24/06 Jan 02/06 Marston, Stephen Adair 00 - Opening Balance-Initial SEDI Report Common Shares
Feb 23/06 Feb 23/06 SETH, WAZIR, CHAND 11 - Acquisition carried out privately Common Shares 20,000 $5.250
Feb 23/06 Dec 09/05 SETH, WAZIR, CHAND 00 - Opening Balance-Initial SEDI Report Common Shares
Feb 23/06 Feb 23/06 Sametz, Peter D. 11 - Acquisition carried out privately Common Shares 5,000 $5.250
Feb 23/06 Feb 23/06 Gusella, Richard Allan 11 - Acquisition carried out privately Common Shares 10,000 $5.250
Feb 06/06 Feb 01/06 Kines, Richard Robert Joseph 90 - Change in the nature of ownership Common Shares 20,000 $5.470

[XIO]

...Mensch, das hört ja garnicht auf heute

Connacher Oil and Gas Limited signs definitive agreement to acquire Montana Refining assets

3/2/2006


CALGARY, Mar 2, 2006 (Canada NewsWire via COMTEX) --

CONNACHER OIL AND GAS LIMITED ("Connacher") - (CLL - TSX) is pleased to announce that today its wholly-owned subsidiary, Montana Refining Company, Inc. ("MRC" or the "Buyer"), has signed a definitive and binding Asset Purchase Agreement whereby MRC will acquire and Montana Refining Company, a Partnership ("Seller") will sell to MRC all right, title and interest in an 8,300 bbl/d refinery, together with related structures and specified tangible assets located in Great Falls, Montana, U.S.A. The Seller is an affiliate of Holly Corporation (NYSE - HOC) of Dallas, Texas.

Additionally, MRC will acquire certain inventory comprised of both petroleum products and equipment. There is also a provision for adjustments related to a planned refinery turnaround, scheduled to commence in April 2006 and for certain capital investments related to the planned installation of a NaHs Unit upgrade to meet emerging air quality standards.

At closing, which is expected to occur on or before April 1, 2006, Connacher`s subsidiary intends to offer employment to the valued individuals associated with the refinery. Closing of the acquisition by MRC is subject to a number of conditions, customary for a transaction of this nature.

The consideration for the purchase is approximately US$55 million, comprised of cash and one million (1,000,000) Connacher common shares from treasury. Mustang Capital Partners Inc. of Calgary, Alberta acted as Connacher`s advisors in the transaction.

Connacher anticipates financing the transaction and related costs substantially with a new US$51 million bridge financing to be provided by BNP Paribas (Canada). Connacher also anticipates it will refinance this indebtedness from a proposed US$148 million term debt facility, which Connacher also anticipates will be arranged for it by BNP Paribas after the scheduled closing of the refinery purchase, pursuant to a previously-executed Mandate Letter. If as anticipated the term debt facility is completed on satisfactory terms, forecast surplus proceeds after repayment of the bridge facility would be utilized to supplement Connacher`s available cash flow and cash balances to finance capital expenditures at the Company`s Great Divide SAGD oil sands project, situated approximately fifty miles southwest of Fort McMurray in northeastern Alberta, Canada.

The proposed refinery purchase is anticipated to complement the previously-announced acquisition by Connacher of Luke Energy Ltd. ("Luke"), an Alberta natural gas producer. This transaction is scheduled to close on March 16, 2006 and will provide Connacher with new natural gas production and thereby hedge its anticipated initial requirements for natural gas to create steam for its proposed SAGD operation at Great Divide. Based on current Luke production volumes, the Luke purchase will also provide surplus volumes for sale in the marketplace.

At closing, it is anticipated the refinery purchase by MRC will provide Connacher with protection against the wider and more volatile crude oil price differential swings which have become increasingly frequent in a higher oil price environment for heavy oil such as would be produced at Great Divide. Furthermore, MRC is anticipated to be a profitable and strong business unit which, based on recent experience, has the potential to contribute to Connacher`s anticipated cash flow growth in 2006 and beyond.

Connacher recently completed a $100 million equity financing, increasing its cash balances before the refinery and Luke purchases to approximately $165 million. Accordingly, in the opinion of its management, Connacher has also significantly mitigated the balance sheet risk normally associated with financing a major capital program such as that anticipated for its Great Divide project.

Connacher Oil and Gas Limited is a public Canadian crude oil and natural gas company. Its principal asset is a 100 percent interest in 110 sections (70,400 acres) of leases at its Great Divide oil sands project in northeastern Alberta. In August 2005 Connacher submitted its application to regulatory authorities to develop this project and is awaiting approval to proceed with the proposed development program in 2006. Connacher also holds conventional producing properties in the Province of Saskatchewan and owns a 33 percent equity stake in Petrolifera Petroleum Limited (PDP - TSX), which company recently announced a number of significant crude oil discoveries on its Puesto Morales/Rinconada concession located in the Neuquen Basin, Argentina. Connacher is in the process of acquiring Luke Energy Ltd. and certain refining assets in Montana, as described herein.

This press release contains forward-looking statements, including statements related to the proposed acquisition of Luke and the refinery assets, anticipated financial performance of MRC and production volumes of Luke. These statements are based on current expectations that involve a number of risks and uncertainties, which could cause actual results to differ from those anticipated. These risks include, but are not limited to, risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections in relation to production, costs and expenses and health, safety and environmental risks), the risk of commodity price and foreign exchange rate fluctuations, the risks and uncertainties associated with securing the necessary regulatory approvals and financing to proceed with the Great Divide project and the uncertainties associated with negotiating and completing commercial transactions such as acquisition of the refinery assets, the purchase of Luke Energy Ltd. and completion of the requisite financing in support thereof. The acquisition of Luke is subject to receipt of shareholder and court approvals and certain other conditions, and the acquisition of the refinery assets is subject to the satisfaction of a number of conditions precedent. There can be no assurances that such approvals will be obtained and the other conditions relating to such acquisitions will be satisfied.

Due to the risks, uncertainties and assumptions inherent in forward- looking statements, prospective investors in the company`s securities should not place undue reliance on these forward-looking statements. For additional information relating to the risks and uncertainties facing Connacher, refer to Connacher`s Revised Initial Annual Information Form for the year ended December 31, 2004 which is available on SEDAR at www.sedar.com.

SOURCE: Connacher Oil and Gas Limited

contact: Richard A. Gusella, President and Chief Executive Officer, Connacher Oil an Gas Limited, Phone: [phone], Fax: [phone], [e-mail], www.connacheroil.com
Copyright (C) 2006 CNW Group. All rights reserved.

[XIO]

Canadian firm buys U.S. refinery

DALLAS, March 3 (UPI) -- A unit of Connacher Oil & Gas Ltd. of Calgary, Alberta, will pay $55 million for Holly Corp.`s small Montana oil refinery.

The cash-and-stock deal for Montana Refining Co.`s 8,000-barrel-per-day facility, set to close by April 1, includes related assets in Great Falls, Mont.

Upon closing, Dallas-based Holly will operate a 75,000-barrels-per-day refinery located in Artesia, N.M., and a 26,000-barrel-per-day facility in Woods Cross, Utah.

http://upi.com/NewsTrack/view.php?StoryID=20060303-075049-93…

[XIO]

Vor dem Hintergrund schwindender Ölreserven interessieren sich Energiekonzerne zunehmend für die Gewinnung von Öl aus Teersand. Die zweitgrößte Ölreserve der Welt lagert – in der Form von eben diesem Teersand – unter der kanadischen Provinz Alberta.

http://www.heise.de/tr/artikel/bilderstrecke/1

[XIO]

http://www.hollycorp.com/refineries_montana.cfm



Montana Refinery

Our petroleum refinery in Great Falls, Montana processes primarily sour Canadian crude oils and primarily serves markets in Montana. Beginning January 1, 2004 the crude oil capacity of the refinery was increased from 7,000 BPSD to 8,000 BPSD as a result of continued improvements at the refinery.

The Montana Refinery is located on a 56 acre site and is a fully integrated refinery with crude distillation, vacuum distillation, FCC, HF alkylation, catalytic reforming, hydrodesulfurization, isomerization, sulfur recovery, and product blending units. Other supporting infrastructure includes approximately 0.6 million barrels of feedstock and product tankage, extensive asphalt blending / loading facilities, maintenance shops, warehouses and office buildings. The operating units at the Montana facility include newly constructed units, older units that have been relocated from other facilities, upgraded and re-erected in Great Falls, and units that have been operating as part of the Great Falls facility (with periodic major maintenance) for many years, in some very limited cases since before 1960. The crude oil capacity of the Great Falls facility is 8,000 BPSD and typically processes or blends an additional 300 BPSD of natural gasoline and butane.

The Montana Refinery currently obtains its supply of crude oil from suppliers in Canada via a common carrier pipeline that runs from the Canadian border to the refinery. The Montana Refinery’s principal markets include Great Falls, Helena, Bozeman, Billings and Missoula, Montana. We compete principally with three other Montana refineries. The Montana Refinery is currently meeting the applicable new low sulfur gasoline requirements that commenced in 2004.

For the 2005 year, the capital budget for the Montana Refinery totals $2.1 million, most of which is for various refinery improvements. The Montana Refinery is capable, with a minimal additional investment, of producing LSG as required by June 2008 and we are studying changes necessary to comply with ULSD requirements by June 2010.

[XIO]

The Oil Sands Of Alberta



(CBS) There’s an oil boom going on right now. Not in Saudi Arabia or Kuwait or any of those places, but 600 miles north of Montana.
In Alberta, Canada, in a town called Fort McMurray where, this time of year, the temperature sometimes zooms up to zero.
The oilmen up there aren’t digging holes in the sand and hoping for a spout. They’re digging up dirt — dirt that is saturated with oil. They’re called oil sands, and if you’ve never heard of them then you’re in for a big surprise because the reserves are so vast in the province of Alberta that they will help solve America’s energy needs for the next century.
Within a few years, the oil sands are likely to become more important to the United States than all the oil that comes to us from Saudi Arabia.
Correspondent Bob Simon reports: http://www.cbsnews.com/stories/2006/01/20/60minutes/main1225…

[XIO]

The Oil Sands Story: In situ

About 80% of the oil sands in Alberta are buried too deep below the surface for open pit mining. This oil must be recovered by in situ techniques. Using drilling technology, steam is injected into the deposit to heat the oil sand lowering the viscosity of the bitumen. The hot bitumen migrates towards producing wells, bringing it to the surface, while the sand is left in place ("in situ" is Latin for "in place"). Steam Assisted Gravity Drainage (SAGD) is a type of in situ technology that uses innovation in horizontal drilling to produce bitumen. In situ technology is expensive and requires certain conditions like a nearby water source. Production from in situ already rivals open pit mining and in the future may well replace mining as the main source of bitumen production from the oil sands.

Challenges facing in situ process are efficient recoveries, management of water used to make steam, and co-generation of all (otherwise waste) heat sources to minimize energy costs. Other methods of in situ recovery look promising, and are in research stages of development.

http://www.oilsandsdiscovery.com/oil_sands_story/insitu.html

und: http://www.oilsandsdiscovery.com/oil_sands_story/pdfs/insitu…

[XIO]

[XIO]

Hat mal jemand eine Kursprognose von einem Analysten bei der Hand?
Was offizielles wäre mal interessant.
Im Kandada-Board ist nix zu finden http://www.stockhouse.ca/bullboards/forum.asp?symbol=CLL&tab…

[XIO]

http://www.oilsands.cc/publications/projects.asp

[XIO]

Dear Wealth Daily Reader, March 7th CLL close $4.93

At current crude prices these reserves would be worth over $25.7 billion!!! Or over $276 per share
--------------------------------------
I want you to sit down. Turn off the television. Switch off the radio. Tell your significant other and the kids to leave the room.

I want your full attention.

For years I`ve been telling investors about the opportunities in energy. Whether it was coalbed methane, natural gas or oil, I`ve been playing them all with huge success.

Exactly a year ago, I launched the Pure Energy Report, an investment service dedicated to energy stocks. I launched this new service because I knew that energy was going to be one of the hottest markets ever.

In March of this year, I recommended two companies with significant exposure to the Canadian oil sands region.

For the longest time, Alberta, home to the oil sands, was neglected as a potential energy play because the cheap price of oil made tar sand production economically infeasible. That has changed. It has changed forever.

I want to recommend Connacher in Wealth Daily as a way of getting you access to one of the most lucrative oil regions in the world.

It`s still early. Investing in the Canadian oil sands today is like investing in Saudi Arabia in 1960.

Canadian oil sands stocks are going to run long and hard for the next 10 to 15 years. The gains will simply blow you away. You don`t want to miss out.

Below is my report on Connacher. Please take the time to read it. It`ll make you quite a bit of money.

Breaking News:
"Washington`s Energy Department announced that oil prices will remain well above $50 a barrel for years to come, resulting in a greater shift towards more fuel efficient cars and alternative energy sources" - December 12, 2005, Associated Press.


Click Here for YOUR FREE Report

Buy Connacher at Current Levels
Connacher is a Calgary-based oil and natural gas exploration and production company.

The Company`s principal asset is a 100 percent interest in 107 sections of oil sands leases at its Great Divide oil sands project near Fort McMurray, Alberta.

Now, for people who are in the know about oil sands, Alberta is the Park Place and Boardwalk of oil sands property. And Connacher`s oil sands sections cover 68,480 acres. That`s twice the size of San Francisco!

Connacher also maintains conventional production at Battrum, Tompkins, and Steelman, Saskatchewan. The Company also owns 35 percent of and manages Petrolifera Petroleum Limited, which has interests in Argentina and Peru.

Now before you read the next sentence, I think you should focus your eyes. Okay. Are you ready?

As it stands now, Connacher controls recoverable reserves of 311 million barrels of oil!

These reserves have a current value of over $18.6 Billion dollars! Yeah, that`s Billion with a "B".

Connacher`s reserves equates to about 3.34 barrels per share or, at $60 per barrel for oil, $200 per share!

But there`s more…

Connacher just signed a monster deal to acquire another Alberta-based company that`s going to take their production to a whole new level.

But first, let me tell you more about Connacher`s strategic operations.

Operations
Canadian Operations

Like I said, Connacher has four interests in Canada. These interests are located in northeast Alberta and southern Saskatchewan.

Connacher`s principal Canadian asset is its Great Divide oil sands project, 50 miles southwest of Fort McMurray. The company has been exploring this lease since 2004.

And based on the results of this exploration, Connacher expects the Great Divide Oil Sands Project to produce 10,000 barrels of bitumen per day for approximately 25 years!

Just at today`s oil prices, Connacher`s gross production value would be worth $600,000 a day!

The further development of the Great Divide oil sands project will incorporate multi-well production pads and horizontal wells, with centralized steam generation, bitumen treating and produced water recycling facilities.

The Company hopes to proceed with the construction of this project in early 2006, following regulatory approvals.

Connacher estimates the Great Divide project area contains up to 180 million barrels of bitumen!!!

That means, with current prices, this reserve is worth $10.8 Billion.

Connacher plans to use the Steam Assisted Gravity Drainage (SAGD) process to produce bitumen.

There are at least nine other projects in the province producing bitumen from the McMurray formation using this same SAGD process.

SAGD typically involves drilling a pair of directional wells which are horizontal for 600 to 800 meters at the base of the reservoir.

The production well is drilled near the base of the reservoir and the injector is drilled five meters above it.

Steam is continuously injected through the upper well bore into the reservoir and a steam chamber is formed to heat the formation and the bitumen.

The heated bitumen drains into the lower horizontal well and is produced to the surface.

Connacher is now in the process of finalizing the conceptual plant designs and expects to open a new facility in early 2006.

On top of the Great Divide oil sands project, Connacher also maintains conventional oil production at Battrum, Tompkins and Steelman, Saskatchewan.

Check them out:

Battrum
Core production of 825 bbl/d
Multi-well drilling program based on 3D seismic results - yielded 50% production growth in 2005 year-to-date
Growth potential in the area
Possible candidate for EOR (ASP flood)
Tompkins
Large contiguous land spread
Sensitive ecosystem
Oil and natural gas in Upper Shaunavon
Significant Working Interest of 60 to 100 percent
Steelman
Light oil
Undrilled spacing units
Verticals could set up further horizontals
Waterflood possibilities under review
The Canadian interests mentioned above would produce enough oil for any company to remain profitable for many years.

But for Connacher, just being profitable isn`t enough. Connacher wants to swing for the fences. That`s why they`ve also acquired some South American interests as well.


South American Operations

Connacher created Petrolifera Petroleum Limited to hold foreign assets.

Petrolifera holds blocks in Argentina and two licenses in Peru.

Argentina
100 percent owned and operated
Light oil and natural gas
Only one exploratory well in 30 years
On trend with major fields
Recent 3D seismic over the blocks; nine drillable prospects
Up to five wells in 2005, subject to rig availability
Peru
Petrolifera received a license over block 106 on July 12, 2005, and a license over block 107 on September 1, 2005.

Connacher Oil and Gas Limited of Calgary, Alberta was responsible for the creation and financing of Petrolifera and remains the single largest shareholder with a 35 percent stake. Connacher also provides management services to Petrolifera.
Visit Connacher Oil and Gas Limited
http://www.connacheroil.com

Maranon Block 106
Comprises 8000 km2 (1,977,500 acres) - oil
Located on basin hingeline along which most oil has been found
Oil pipeline on Block
Surrounds the Corrientes Field >200 MMBO(1)
Area has excellent reservoirs and no seal problems
Many of the reservoirs filled to spill point
Block has access to good hydrocarbon charge
Numerous prospects and leads in the Cretaceous
Deep potential within the Paleozoic section - untested
Ucayali Block 107
Large Block of approximately 13,000 km² (3,205,000 acres) - natural gas, condensate, oil
On trend with giant Camisea Field
Existing seismic indicates Camisea-like structures on Block
Undrilled, large mapped surface anticlines identified, may contain giant accumulations
Rashaya Norte - an Aguaytia Field (440 BCF, 20 MMBC(1)) look-alike
Giant reserve and company-maker potential
Ok, now that you know a little more about Connacher`s current operations, let me tell you about Connacher`s new baby, Luke Energy.

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Luke Energy

Luke Energy is another Calgary-based oil and natural gas exploration and production company.

Luke`s operations are located in Alberta. Let me quickly run through some of the highlights from each interest.

Marten Creek
Production ~ 15 mmcfpd (2,500 boepd)
Multi-zone shallow gas area; 1 to 2 bcf/section
Land - 100% in 41,600 acres
12.5% to 70% in 5,120 acres
Additional drilling program, Q1, 2006 Seal/Clear Prairie
New gas discovery at Seal
Cretaceous gas potential; depth 1,200 - 2,000 ft.
Land - Seal - 88% in 6,400 acres
Clear Prairie - 100% in 3,840 acres
Option on 12,032 acres
New drilling, Q1, 2006
Three Hills/Bashaw
Production ~ 235 boepd (73% oil)
Multi-zone - Ostracod & Nisku oil
Pekisko gas
Land - 97% in 10,400 acres
Dev. drilling and waterflood potential, Q4, 2005 Gold Creek/Karr/Latornell
Cretaceous gas potential; 5,000 - 6,800 ft.
Land 100% in 5,530 acres
Additional prospective land
New drilling in Q4, 2005 and Q1, 2006
Now, on a combined basis, Connacher could immediately have a production base of approximately 3,500 boe/d consisting of approximately 15.7 mmcf/d of natural gas production and approximately 900 bbl/d of oil production.

Recent reserves reports indicate that Luke Energy holds approximately 79.3 million boe, including 69.6 million probable recoverable barrels of bitumen reserves at Connacher`s Great Divide Pod One.

Assuming Pod One development is approved and the project comes on stream at its application rate of 10,000 bbl/d and these volumes are combined with the conventional production rate of 3,500 boe/d, a calculated reserve life index of 16 years is indicated.

A further 38.7 million barrels of possible recoverable reserves have also been assigned to Pod One by a recognized independent consultant.

So by my calculations, when Connacher completes its acquisition of Luke Energy, the Company will have 429 million barrels of proved, probable, and possible oil reserves!!!

At current crude prices these reserves would be worth over $25.7 billion!!! Or over $276 per share.

That`s not bad for a company that`s still trading under four bucks.

Before we wrap this thing up let me tell you about Connacher`s management team.

Senior Management

My Pure Energy subscribers know that I carefully scrutinize a company`s management team way before I recommend it as a buy.

The fact is, any company run by a group of bozos is destined to go belly up.

Connacher`s management is way above par. Here`s just a little bit about them.

Richard A. Gusella
President & Chief Executive Officer
Mr. Gusella has been the President, CEO and a director of Connacher since May 2001. Prior thereto, he was the President of Gusella Oil Investments Limited, a private oil and gas corporation, as well as the Chairman & CEO of Carmanah Resources Limited, a public oil and gas company listed on the Toronto Stock Exchange. Mr. Gusella was President and Chief Executive Officer of Sceptre Resources Limited from 1979 to 1991 during which time the company grew from approximately 500 boe/d to 50,000 boe/d. He is a past chairman of IPAC prior to its combination with CPA to form CAPP.

Peter D. Sametz
Executive Vice President & Chief Operating Officer
Mr. Sametz has approximately 25 years of experience in the oil industry. He graduated with high distinction as an Engineer from Carleton University in 1979 and has worked with large, intermediate and junior companies, managing up to 40,000 boe/d of production. His industry expertise has been further drawn upon for technical papers, lectures, and domestic and international consulting services.

Richard R. Kines
Vice President, Finance & Chief Financial Officer
Mr. Kines holds a C.A. designation and has been with Connacher since 2002. He was appointed Chief Financial Officer in June, 2003. He has over 25 years experience, in public practice, and with various oil and gas and oil service companies.

Timothy J. O`rourke
Vice President, Oil Sands Operations
Mr. O`Rourke has extensive experience in oil and gas operations with a number of companies, including Sceptre Resources Limited and Deer Creek Energy Limited, where he was a founding shareholder prior to joining Connacher in 2002. His experience in conventional production, horizontal drilling and SAGD applications will assist in the timely evaluation and development of the company`s Great Divide project.
http://www.wealthdaily.net/newsletters/dec05/122005.php
---------------------------------------------

News Releases

20060303 In the News Globe says ING, others seen joining major index

20060302 News Release Connacher sub to acquire Montana refinery

20060223 News Release Connacher Oil and Gas closes $100-million financing

20060221 News Release Connacher Oil and Gas drills 10 wells at Great Divide

20060210 News Release Connacher Oil and Gas to acquire Luke Energy

[XIO]

[wmuehli]

[posting]20.584.465 von XIO am 08.03.06 21:07:20[/posting] der derzeitige Kurs sagt gar nichts aus. Wie ich schon in #4 gepostet habe hat Michael Schaefer sie auf seiner Empfehlungsliste und gibt den "Alberta Oil Sand" playern sehr gute Chancen. Ölpreis muß und wird mitspielen.

allerdings eher "Langfrist-Investment", mit verbesserter Technik und dem Ölpreis wird das was "Großes".

Trend: 1x buy, 1x strong buy, Meinung für Kursziel $ 5,50, nicht gerade berauschend.

Man muß sehen, wie 2006 von den Ergebnissen her läuft, die Positionierung scheint zu stimmen (nicht nur Alberta).

[XIO]

[posting]20.588.311 von wmuehli am 09.03.06 07:41:32[/posting]Sag mal, wer ist eigentlich dieser Michael Schaefer, ein Wurstblattherausgeber oder jemand mit gehobenem Niveau???

[XIO]

China eyes Canada’s oil sands
By Fred Stakelbeck Jr. Mar 10, 2006, 13:18 GMT

China’s burgeoning energy needs have led the developing country to the western shores of resource-rich Canada, where abundant supplies of oil, natural gas and valuable minerals lay undisturbed deep beneath the frozen soil.

China’s evolving energy strategy, however, focuses primarily upon a relatively unknown hydrocarbon resource -- Canada’s vast, untapped oil sands deposits, found primarily in northern Alberta. Of the country’s approximate 179 billion barrels of proven oil reserves, 95 percent are oil sands deposits. “Canada’s oil sands reserves are so huge; we should never ignore it as it offers an effective supply alternative,” noted one official from China National Petroleum Corp. (CNPC).

Weiter:
http://news.monstersandcritics.com/asiapacific/article_11360…

[XIO]

[XIO]

Saugen!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

http://161.58.230.171/raymond_james-6.50_CLL.pdf

[XIO]

Und ab gehts

Press Release Source: Standard & Poor`s Canadian Index Operations


Standard & Poor`s Announces Changes In S&P/TSX Canadian Indices
Monday March 13, 5:17 pm ET


TORONTO, March 13 /CNW/ - Standard & Poor`s Canadian Index Operations announces the following index changes as a result of the Quarterly S&P/TSX Composite Index Review. These changes will be effective after the close of business on Friday, March 17, 2006:

S&P/TSX Composite Index

-------------------------------------------------------------------------
ADDS
-------------------------------------------------------------------------
60/MidCap/ Live Composite GICS
Issue Name Symbol SmallCap Sector Index
-------------------------------------------------------------------------
Alamos Gold Inc. AGI SmallCap Materials, Gold
-------------------------------------------------------------------------
Cardiome Pharma Corp. COM SmallCap Health Care
-------------------------------------------------------------------------
Connacher Oil & Gas Limited CLL SmallCap Energy
-------------------------------------------------------------------------
Eurozinc Mining Corporation EZM SmallCap Materials, Div. Metals
-------------------------------------------------------------------------
ING Canada Inc. IIC.LV SmallCap Financials
-------------------------------------------------------------------------
Petrobank Energy & Resources Ltd. PBG SmallCap Energy
-------------------------------------------------------------------------
Silver Wheaton Corp. SLW SmallCap Materials
-------------------------------------------------------------------------
UEX Corporation UEX SmallCap None
-------------------------------------------------------------------------


Changes to the S&P/TSX Composite Index will also affect the S&P/TSX Capped Composite Index. Stocks added to or removed from the S&P/TSX Composite Index will also be added to or removed from the appropriate Global Industry Classification Standard (GICS) index. Income Trusts that are part of the S&P/TSX Composite Index will now be at full capitalization after this review. Calculation of the 4 provisional indices launched in the September, 2005, quarterly index review (Provisional S&P/TSX Composite, Capped Composite, MidCap and SmallCap indices) will terminate after the close of Friday, March 17, 2006. At that time, their constituent names and relative weights will exactly match those of the S&P/TSX Composite, Capped Composite, MidCap and SmallCap indices, respectively.
Company additions to and deletions from an S&P index do not in any way reflect an opinion on the investment merits of the company.

Standard & Poor`s is the world`s foremost provider of independent credit ratings, indices, risk evaluation, investment research, data and valuations. With approximately 6,500 employees located in 22 countries, Standard & Poor`s is an essential part of the world`s financial infrastructure and has played a leading role for more than 140 years in providing investors with the independent benchmarks they need to feel more confident about their investment and financial decisions. For more information, visit www.standardandpoors.com.


Founded in 1888, The McGraw-Hill Companies is a leading global
information services provider meeting worldwide needs in the financial
services, education and business information markets through leading brands
such as Standard & Poor`s, BusinessWeek and McGraw-Hill Education. The
Corporation has more than 280 offices in 37 countries. Sales in 2005 were $6.0
billion. Additional information is available at http://www.mcgraw-hill.com..

For further information

Tony North, [phone], [e-mail]
Dave Guarino, [phone], [e-mail]

[XIO]

[XIO]

12:44 EST Wednesday, March 15, 2006

/NOT TO BE DISTRIBUTED IN THE UNITED STATES OF AMERICA OR THROUGH U.S. WIRE SERVICES/

CALGARY, March 15 /CNW/ - Luke Energy Ltd. ("Luke") (TSX: LKE) is pleased to announce that it has received overwhelming Luke Shareholder approval in accordance with all legal and regulatory requirements at the special meeting of Luke Shareholders held on March 15, 2006 to the previously announced Plan of Arrangement (the "Arrangement") involving Connacher Oil and Gas Limited pursuant to which each holder of Luke Shares will receive $2.31 in cash and 0.75 of a common share of Connacher for each common share of Luke held. Subject to approval of the Arrangement by the Court of Queen`s Bench of Alberta later today, it is expected that the acquisition by Connacher of the outstanding shares of Luke and the other transactions contemplated by the Arrangement will be completed on March 16, 2006.

[FANNIEMAE]

[posting]20.670.643 von XIO am 14.03.06 08:11:16[/posting]14.30 --> Blocktrade 1.5 mio shares

nicht schlecht . Jetzt kommt wieder Pfeffer rein.

[XIO]

Luke Energy Ltd. acquired by Connacher Oil and Gas Limited

/NOT TO BE DISTRIBUTED IN THE UNITED STATES OF AMERICA OR THROUGH U.S. WIRE SERVICES/

CALGARY, Mar 16, 2006 (Canada NewsWire via COMTEX) --

Luke Energy Ltd. ("Luke") - (LKE - TSX) - announced today that Connacher Oil and Gas Limited ("Connacher") has completed the previously announced acquisition of all of the outstanding common shares ("Luke Shares") of Luke by way of a business combination under a court approved Plan of Arrangement (the "Arrangement") involving Connacher, Luke and a wholly-owned subsidiary of Connacher. Under the Arrangement, holders of Luke Shares will receive $2.31 in cash and 0.75 of one common share of Connacher for each Luke Share held, resulting in the payment of approximately $91.5 million and the issuance from treasury of approximately 30 million common shares of Connacher.

Connacher has advised Luke that Connacher has today completed filings with the Toronto Stock Exchange to delist the Luke Shares and expects delisting of the Luke Shares to occur within two or three business days following the date hereof. Luke has also been advised by Connacher that it has made application to the local securities regulatory authority or regulator in each jurisdiction in which Luke is a reporting issuer for a decision that Luke has ceased to be a reporting issuer in each such jurisdiction.

Forward-Looking Statements: This press release contains certain forward- looking statements within the meaning of applicable securities law. Forward- looking statements are frequently characterized by words such as "plan", "expect", "project", "intend", "believe", "anticipate", "estimate" and other similar words, or statements that certain events or conditions "may" or "will" occur. Forward-looking statements are based on the opinions and estimates of management at the date the statements are made, and are subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those projected in the forward-looking statements. Luke undertakes no obligation to update forward-looking statements if circumstances or management`s estimates or opinions should change, unless required by law. The reader is cautioned not to place undue reliance on forward-looking statements.

SOURCE: Luke Energy Ltd.

Richard A Gusella, President and Chief Executive Officer, Luke Energy Ltd., Phone: [phone], Fax: [phone]
Copyright (C) 2006 CNW Group. All rights reserved.

[XIO]

Connacher Oil and Gas Ltd (C-CLL) - News Release
Luke Energy gets shareholder nod for Connacher takeover

2006-03-15 12:55 ET - News Release
Shares issued 160,279,703
CLL Close 2006-03-14 C$ 5.12

From News Release (C-LKE) Luke Energy Ltd


Mr. Harold Pedersen of Luke reports

LUKE ENERGY LTD. ANNOUNCES SHAREHOLDER APPROVAL FOR THE SALE TO CONNACHER OIL AND GAS LIMITED

Luke Energy Ltd. has received overwhelming Luke shareholder approval in accordance with all legal and regulatory requirements at the special meeting of Luke shareholders, held on March 15, 2006, to the previously disclosed plan of arrangement involving Connacher Oil and Gas Ltd., pursuant to which each holder of Luke shares will receive $2.31 in cash and 0.75 of a common share of Connacher for each common share of Luke held. Subject to approval of the arrangement by the Court of Queen`s Bench of Alberta later on March 15, it is expected that the acquisition by Connacher of the outstanding shares of Luke and the other transactions contemplated by the arrangement will be completed on March 16, 2006.

[XIO]

Das Ding ist im Kasten

[XIO]

http://www.petrolifera.ca/


Tochterunternehmen von Connacher in Südamerika

[XIO]

From the TSX website:
March 13, 2006


Effective after the close of business on Friday, March 17, 2006

Alamos Gold Inc. (AGI) will be added to the S&P/TSX Composite, the S&P/TSX Capped Composite, the S&P/TSX SmallCap, the S&P/TSX Materials, the S&P/TSX Gold Indices.
Cardiome Pharma Corp. (COM) will be added to the S&P/TSX Composite, the S&P/TSX Capped Composite, the S&P/TSX SmallCap, the S&P/TSX Health Care Indices.

Connacher Oil and Gas Ltd. (CLL) will be added to the S&P/TSX Composite, the S&P/TSX Capped Composite, the S&P/TSX SmallCap, the S&P/TSX Energy Indices.

EuroZinc Mining Corp. (EZM) will be added to the S&P/TSX Composite, the S&P/TSX Capped Composite, the S&P/TSX SmallCap, the S&P/TSX Materials, the S&P/TSX Diversified Metals Indices.
ING Canada Inc. (IIC.LV) will be added to the S&P/TSX Composite, the S&P/TSX Capped Composite, the S&P/TSX SmallCap, the S&P/TSX Financial Indices.
Petrobank Energy & Resources Ltd. (PBG) will be added to the S&P/TSX Composite, the S&P/TSX Capped Composite, the S&P/TSX SmallCap, the S&P/TSX Energy Indices.
Silver Wheaton Corp. (SLW) will be added to the S&P/TSX Composite, the S&P/TSX Capped Composite, the S&P/TSX SmallCap, the S&P/TSX Materials Indices.
UEX Corp. (UEX) will be added to the S&P/TSX Composite, the S&P/TSX Capped Composite, the S&P/TSX SmallCap Indices

[luto9]

man beachte die Käufe nach 16 Uhr

16:54:47 T 5.20 +0.08 24 85 Scotia 85 Scotia E

16:53:25 T 5.20 +0.08 18,800 85 Scotia 85 Scotia S

16:40:19 T 5.20 +0.08 5,000 79 CIBC 46 Blackmont K

16:32:32 T 5.20 +0.08 1,000 79 CIBC 46 Blackmont K

16:32:32 T 5.20 +0.08 5,000 79 CIBC 94 Hampton K

16:30:22 T 5.20 +0.08 1,187,400 7 TD Sec 7 TD Sec S

16:29:47 T 5.20 +0.08 12 7 TD Sec 7 TD Sec E

16:10:02 T 5.20 +0.08 9,100 2 RBC 14 ITG KQ

16:10:02 T 5.20 +0.08 1,500 2 RBC 7 TD Sec KQ

16:10:02 T 5.20 +0.08 900 3 Tristone 7 TD Sec KQ

[maulesel]

Also ich würd das Ding erst über 4,50 Kaufen
der Chart sieht eher aus wie ein Starway to hell.
Nichts für ungut, will euch eure Illusionen nicht nehmen.
Gruß

[XIO]

Map zu Download: http://www.industrialinfo.com/prodserv/prodserv.jsp?pagerequ…

[XIO]

[posting]20.854.801 von maulesel am 19.03.06 18:11:53[/posting]...CLL wird long auf 20-30€ gehen, oder übernommen.
Das Syncrude Projekt lässt grüssen.

[XIO]

"Peak Oil is Now Official"

By Trevor Shaw
Mar. 18, 2006

Cantarell is second only to Saudia Arabia`s Ghawar oilfield and has been pumping millions of barrels of light crude a day since 1976. According to Carlos Morales, production manager for Mexico`s state owned oil company, Pemex, Cantarell`s projected output will be 6 percent lower this year at 1.9 million barrels per day and down to 1.43 million barrels by 2008, the level of production in 2000.

A leaked internal memo from inside Pemex said water and gas were seeping into the massive offshore oil field. Cantarell is showing the signs of peaking.

Canterell`s Output Levels

Year Output
1994 1.0 mb/d
2000 1.5 mb/d
2004 2.13 mb/d (Peak)
2005 2.0 mb/d
2006 1.9 mb/d (projected)
2008 1.43 mb/d (projected)

To make up the decline of Cantarell, Pemex is spending billions to develop new fields such as Chicontepec. This will prove difficult for a company that lost $3.75 billion in 2005, during a time of record high crude prices.

The crude that is first produced from any field is light and sweet, it flows well, and is easy to refine. Not so the later output, and Pemex is faced with spending billions to reconfigure its refineries so they can handle heavier crude.

Pemex`s Galindo, like many outside experts, thinks the era of easy, cheaply produced oil in Mexico appears to be over. The remaining crude left in Cantarell or in existing fields will most certainly be heavier and costlier.

The Cantarell field accounts for 60 percent of Mexico`s total production. To make up for the anticipated decline of 500,000 bpd will be difficult to achieve and definitely more expensive if even possible. Mexico is the second-largest supplier of oil to the U.S. market. The decline will intensify America`s dependence on Middle East oil.

Many experts - Matthew Simmons, Richard Heinberg, Colin Campbell, Bilaal Abdullah and members of the Association for the Study of Peak Oil - have said that when Ghawar Peaks so does the world.

Rumours and experts outside Saudi Aramco, Saudi Arabia`s state controlled oil company, believe Ghawar has already peaked or is currently peaking. It is definitely showing symptoms. Some reports have stated that the water cut level is nearing 50 percent of the total liquids being pumped out by its more than 300 wellheads.

Combined with the news in January, 2006 from the Kuwait Oil Company that their super giant Burgan oil field has peaked, this strongly suggests we are in Peak Oil.

[XIO]

We Were Warned Tomorrow`s Oil Crisis



http://www.cnn.com/CNN/Programs/presents/

[TomCole]

Antwort auf Beitrag Nr.: 20.755.899 von XIO am 17.03.06 09:12:05

Thema: <<< Petrolifera Petroleum Ltd. >>>

siehe auch Thread: <<<] Petrolifera Petroleum Ltd. [>>>

[XIO]

Antwort auf Beitrag Nr.: 20.938.143 von TomCole am 24.03.06 15:10:31

Peter Hodson of SprottAsett Management was on

www.robtv.com

today at 12:30, talked about CLL est 40 min into the show, is NOW a believer in CLL see's it possible at $10, also has PDP as one of his top picks looking at NAV of $16....worth a listen later today on the video

[XIO]

Antwort auf Beitrag Nr.: 20.965.902 von XIO am 27.03.06 21:03:18

Holly Closes Sale of Montana Refinery Assets to Connacher

DALLAS, March 31, 2006 /PRNewswire-FirstCall via COMTEX/ --

Holly Corporation (NYSE: HOC) announced today the closing of the divestiture of the assets of Montana Refining Company, a Partnership, to a subsidiary of Connacher Oil & Gas Limited (TSX: CLL) of Calgary, Alberta, effective at 11:59 PM, March 31, 2006. Subject to certain closing adjustments, the purchase price for the assets including inventories is approximately $55 million and consists of cash and 1,000,000 shares of Connacher common stock.

ABOUT HOLLY

Holly Corporation, headquartered in Dallas, Texas, is an independent petroleum refiner and marketer that produces high value light products such as gasoline, diesel fuel and jet fuel. Holly operates through its subsidiaries a 75,000 barrels per day ("bpd") refinery located in Artesia, New Mexico and a 26,000 bpd refinery in Woods Cross, Utah. Holly also owns a 45% interest (including the general partner interest) in Holly Energy Partners, L.P.

The following is a "safe harbor" statement under the Private Securities Litigation Reform Act of 1995: The statements in this press release relating to matters that are not historical facts are "forward-looking statements" within the meaning of the federal securities laws. These statements are based on our beliefs and assumptions using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties, including those contained in the company's filings with the Securities and Exchange Commission. Although the company believes that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that our expectations will prove correct. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. The forward- looking statements speak only as of the date made, other than as required by law, and we undertake no obligation to publicly update or revise any forward- looking statements, whether as a result of new information, future events or otherwise.

SOURCE Holly Corporation

[XIO]

Holly Corporation completes sale of Montana Refinery assets to Connacher

Apr 03, 2006 (M2 EQUITYBITES via COMTEX) --

Holly Corporation (NYSE:HOC), a petroleum refiner and marketer, declared on 31 March the completion of the divestiture of the assets of Montana Refining Company, a partnership, to a subsidiary of Connacher Oil & Gas Limited (TSX:CLL) of Calgary, Alberta, Canada, with immediate effect.

The purchase price for the assets including inventories is approximately USD55m and consists of cash and 1m Connacher common shares and is subject to certain closing adjustments.

Comments on this story may be sent to [e-mail]
(C)2006 M2 COMMUNICATIONS LTD http://www.m2.com

[XIO]

Research Report

Connacher Oil and Gas Ltd.1 BUY
CLL $4.95 Target: $6.30

A detailed Coverage Initiation report will be available to clients over the coming days

COMPONENTS NOW IN PLACE FOR DEVELOPMENT OF GREAT DIVIDE SAGD BITUMEN PROJECT
Introduction
Connacher Oil and Gas Ltd. (CCL) is a western Canadian junior producer that trades on the TSX
exchange under the ticker CLL. The company has current production from conventional assets in
Alberta and Saskatchewan, weighted to natural gas, but its main asset and the key growth driver for
shareholders is its Great Divide oil sands property in northeast Alberta, which is set to see first
production next year. In addition, CLL recently acquired a heavy oil refinery in Montana that will serve
as a hedge against heavy oil price volatility once the oil sands project is on stream. As well, CLL late
last year spun out its South American assets into a separate entity called Petrolifera (PDP-TSX)
through an IPO, while retaining approximately 33% of the equity in that new company.
Initiating coverage on this oil sands junior
• Components now in place for development of Great
Divide SAGD bitumen project
• Management team has a solid technical footing in
heavy oil and oil sands
• Pending EUB approval is final element for full
development of Great Divide
• We estimate 2005 NAV at $3.24 per share
• We anticipate additional upside to the $7.50 - $8.00
per share range beyond the next 12 months
• Initiating coverage with a BUY rating and $6.30 target

CLL currently has 189.7 million common shares outstanding, which at Friday’s closing price of $4.95
gives the company a market capitalization of $939 million. This year, CLL has issued equity from
treasury on three occasions:
• In February, CLL issued $100 million in equity through the offering of 19 million shares at
$5.25 each. GMP acted as lead underwriter in that offering, with proceeds being applied to
the start up costs of the Great Divide oil sands project.
• On March 2, issued 1 million common shares (along with a cash component) for the US$55
million purchase of a 100% stake in an 8,300 b/d refinery in Montana from Montana Refining
Company, a wholly-owned subsidiary of Holly Corporation (HOC-NYSE), which is expected to
close on March 31st.
• On March 16, closed the previously announced purchase of Luke Energy at a total cost of
$240 million, including the issuance of 30 million CLL shares and $91 million cash.
Common share equivalents in CLL consist of 8.6 million options at an average exercise price of $1.49
each, and 1.5 million warrants with an average exercise price of $0.59 each, of which most expire on
June 7, 2006, and the balance expire on December 1, 2006.
At year-end 2005, CLL had no debt and approximately $75 million in cash, but with the Luke and
Montana refinery purchase this month, offset by the $100 million financing, we estimate current net debt
is around nil. CLL recently completed three loan agreements: 1. a $45 million reserve-based revolver
plus $10 million operating revolver (both undrawn at present); 2. a commitment letter for a US$51
million bridge loan for the refinery acquisition, which will bear interest at LIBOR + 0.5% (~5.5%) and be
available for 364 days from the draw date; and 3. a mandate letter for a US$148 million term loan, to be
executed upon successful negotiation of satisfactory terms and acceptable market conditions. The
term loan would extinguish the bridge loan. To sum it all up, CLL will have net access to approximately
$227 million in credit, which will enable it to execute its aggressive capital program going forward.

MANAGEMENT TEAM HAS A SOLID TECHNICAL FOOTING IN HEAVY OIL AND OIL SANDS
Officers of Connacher
CLL’s management team has well over 100 years of experience in the western Canadian oil patch, including
significant experience with both primary and enhanced oil recovery methods in the heavy oil sector. This
technical team was together at Sceptre Resources, which implemented the first successful SAGD project in
North America at Tangleflags, considered to be the flagship SAGD project during the 1990s.
• Richard (Dick) Gusella, President and Chief Executive Officer: Mr. Gusella has been in his current
position as President and CEO of CLL since 2001. Prior thereto Mr. Gusella was President of Gusella Oil
investments, as well as Chairman and CEO of Carmanah Resources. Mr. Gusella was also President and
CEO of Sceptre Resources, which grew from 500 boe/d to 50,000 boe/d between 1979 and 1991 and
included significant heavy oil assets.
• Peter Sametz, Executive Vice President and Chief Operating Officer: Mr. Sametz has over 25 years of
industry experience. Prior to joining CLL, Mr. Sametz was COO and a Director of Surge Petroleum, and
also with a heavy oil consulting group, as well as with ELAN Energy and Esso, both companies having
significant exposure to heavy oil. In his career, Mr. Sametz has managed up to 40,000 boe/d at various
large, intermediate and junior E&P companies.
• Richard (Rick) Kines, Vice President, Finance and Chief Financial Officer: Mr. Kines joined CLL in 2002
and was appointed to his current position in June 2003. Prior to Connacher, Mr. Kines was the CFO of
Integrated Production Services Inc. Mr. Kines has over 25 years experience in both public practice and the
oil and gas industry.
• Timothy O’Rourke, Vice President, Oil Sands Operations: Mr. O’Rourke has been with CLL in his current
position since 2002. Prior to joining Connacher, Mr. O’Rourke was a founding shareholder of Deer Creek
Energy Ltd. and worked at Sceptre Resources with Mr. Gusella. Deer Creek was sold last year to Total
E&P Canada for $1.6 billion in a competitive process. Mr. O’Rourke’s experience in the Oil Sands and
SAGD development makes him a key member of the management team.
Directors
• Charles Berard – Partner, McLeod Dixon LLP
• D. Hugh Bessell – Retired Businessman
• Colin Evans – President, Evans & Co., Inc.
• Dick Gusella – President & CEO of Connacher
• Stewart McGregor – President, Camun Consulting Ltd.
• W.C. (Mike) Seth – Chairman, McDaniel & Associates Consultants Ltd.
Advisors
• Auditor – Deloitte & Touche LLP
• Banker – National Bank of Canada, BNP Paribas
• Independent Reserve Engineers –
o Oil Sands – GLJ Petroleum Consultants
o DeGolyer and MacNaughton Canada Ltd.
• Solicitors – McLeod Dixon LLP
CORE AREAS – CONVENTIONAL ASSETS
Conventional Assets bolstered by acquisition of Luke Energy
Prior to the acquisition of Luke Energy this month, CLL’s conventional assets comprised approximately
600 boe/d of mainly medium gravity oil at Battrum and minor production at Tompkins, both in southwest
Saskatchewan. While Battrum does contribute to CLL’s cash flow, we believe that at the appropriate
market terms the property could be divested.
On March 16, Connacher announced that it had successfully acquired all of the issued and outstanding
shares of Luke Energy in a deal that was first announced in December 2005. In the deal, CLL acquired
approximately 2,800 boe/d of production (90% gas) and 7.4 mmboe of proved plus probable reserves
(based on a June 30, 2005 GLJ reserve report) for $2.31/share cash and 0.75 CLL shares per Luke
share. The result was a total cash outlay of ~$91.5 million and the issuance of 30 million common shares
of CLL, or total consideration of ~$245 million based on CLL’s closing price of $5.12 on March 16.
Luke’s production is primarily from its Marten Creek core area located approximately 480 kilometres
north of Calgary. The area is a multi-zone shallow gas play with mainly Cretaceous-aged targets. It is
predominantly a winter-access only area, with Luke having drilled a total of 24 wells with 75% success
during the winter of 2005. The company also added 2 field compressors and one 7 mmcf/d sales
compressor last winter, which optimized production. Production exited 2005 at 15 mmcf/d and the
company had identified over 25 drilling locations on its land, which provides a solid inventory of
opportunities going forward.
The other producing property acquired in the deal is at Three Hills, Alberta. Luke acquired the property
for $8.1 million in July 2005 at which time it was producing 175 boe/d. During the year the company
drilled 4 wells in the area resulting in 2 oil wells, 1 gas well and 1 water injection well bringing
production from the area to 330 boe/d at year-end.
The primary driver behind the Luke acquisition was the natural hedge that it provides for natural gas as
a feedstock for CLL’s Great Divide SAGD bitumen project. As a result, the overall gas price risk is
reduced, as Connacher will now participate on both sides of the gas market. We believe that this is an
effective way to ensure that high gas prices do not jeopardize the economics of Great Divide.

GREAT DIVIDE IS CLL’S MARQUEE PROJECT
CLL got into the play before the great land rush last year
CLL entered the Great Divide project through a small asset acquisition in 2003, and added to its land
position through crown land sales through 2004, such that it now has 100% working interest in over
70,000 acres at an average acquisition price of $20/acre. The great land rush that has occurred since
then has seen oil sands rights sell for over $2,000/acre, and more importantly, most of the lucrative
acreage is now taken up by industry, such that the only way for additional entrants into the oil sands is
through joint ventures or acquisitions.
Bitumen characteristics comparable to similar developments underway
The area is prospective for 8° - 10° gravity API bitumen from the McMurray sands averaging 20-25
metres in net pay thickness at 450 – 475 metres depth. While not as thick as other in situ oil sands
plays in the area, the bitumen content by weight appears to be relatively high, averaging 12% - 16%,
which is greater than other in situ plays, and up to 2x greater than most mining projects. CLL has
evaluated the development of the oil sands using Steam Assisted Gravity Drainage (SAGD) technology,
since the highly-viscous bitumen will not flow to surface using conventional primary recovery methods.
Recovery factors are expected to be up to 60% of in-place reserves. CLL has delineated its Great
Divide region into four pods or SAGD development pools, with work currently underway on full-scale
development of Pod 1 this year, targeting first production by early 2007.
Great Divide oil sands reserves evaluated last year by GLJ
Last summer, GLJ Petroleum Consultants (GLJ) evaluated CLL’s bitumen resource at Great Divide,
with an effective date of September 1, 2005, in accordance with NI 51-101. GLJ assigned 538 mmb of
original oil in place on CLL’s acreage, with initial recoverable reserves of 311 mmb on a proved plus
probable plus possible basis (58% recovery factor). Proved plus probable (P+P) reserves were only
assigned to Pod 1, given the 3D seismic and evaluation drilling that has helped define the resource,
whereas the remaining three pods have insufficient drilling or seismic definition to be classified as
reserves at this time. Pod 1 was assigned 69.6 mmb of initial P+P reserves, using a 15-metre net pay
cutoff. As well, GLJ assumed 45 SAGD well pairs in the P+P case, and 63 well pairs in the 3P case.
Additional upside determined by GLJ
In addition to the initial P+P bookings at Great Divide, GLJ also assigned possible reserves, which it
expects could be updated to P+P with additional drilling and seismic. These possible reserves were
evaluated using a net pay thickness cutoff of 10 metres, as outlined in the following table. In addition,
GLJ considered that along CLL’s Great Divide channel trend, there exists the likelihood that additional
pods will be discovered with additional drilling, and assigned 160.6 mmb of oil in place or 91.6 mmb of
potential recoverable reserves for undiscovered pods. Therefore, total oil in place is 538 mmb, or 311
mmb recoverable.
Possible Great Divide Reserves (mmb)
Source: GLJ
The SAGD process
SAGD implements dual horizontal wells spaced 100 metres apart, and drilled from a single pad (up to 8
well-pairs per pad). Steam is injected into the top horizontal well, which lowers the viscosity of the oil
and allows it to flow to the bottom well bore, where it is pumped to surface. Given the relatively flat
surface of the underlying Devonian formation over which the McMurray lies, CLL believes it will be able
to position the producing well bore fairly close to the bottom of the formation, thereby optimizing the
drainage. In its initial reserve assessment, GLJ assumed a steam-oil ratio (SOR) of 2.6, declining to
2.3 during peak production periods. This implies gas use of 0.87 mcf per barrel of bitumen under the
2.6x SOR, declining to 0.77 mcf per barrel under the 2.3x SOR. CLL has budgeted that each SAGD
well pair will cost $1.8 million to drill ($2.6 million completed and tied-in), and recover 1.5 mmb bitumen,
with peak initial production rates of 1,500 b/d per well, stabilizing in the 500 to 700 b/d range. The
analog to Great Divide is Japan Canada Oil Sands (JACOS) Hangingstone to the north, which is
producing ~10,000 b/d and is exhibiting similar performance characteristics as modelled here.
Facility construction to commence with EUB approval
CLL submitted an application to the Alberta Energy and Utilities Board (EUB) last August for
development approval of Pod 1. The approval is pending, and we expect that it will be granted any time
over the next couple months. Environmental and regulatory risks are minimal, given the number of past
approvals given to industry in the immediate area, and the fact that Great Divide lies over an area hit by
a forest fire in the 1990’s (i.e. most surface damage has already been done by mother nature). Upon
approval, the company will begin construction of a steam/processing facility, which is expected to take
at least 300 days to complete. Designed in a modular fashion to minimize up-front capital, the facility
will have an initial design capacity of 10,000 b/d, and is expected to cost $120 million. Certain longlead
time components have been pre-ordered by CLL in advance of EUB approval. It is expected that
each Pod will be able to sustain production of approximately 10,000 b/d each for up to 25 years. CLL
anticipates that upon start-up of Pod 1, it will be able to finance development of subsequent Pods.


REFINERY ACQUISITION PROVIDES A HEDGE ON HEAVY OIL PRICE VOLATILITY
Earlier this month, CLL announced that it had acquired the refining assets in Great Falls Montana from
Montana Refining Company, a wholly-owned subsidiary of Holly Corporation. The refinery processes
8,300 b/d of heavy oil from Canada, and CLL paid US$55 million, comprised of 1 million CLL shares
and cash. Public records indicate that the CLL paid approximately 3x EBITDA based on the refinery’s
Q4-annualized EBITDA. The acquisition is expected to close at the end of March, and then the refinery
is scheduled to enter a maintenance turnaround period for most of April. CLL made the acquisition as a
surrogate upgrader for its Great Divide project, since its refines heavy crude, it will act as a perfect
hedge to the heavy oil price volatility that will be experienced by CLL when Pod 1 comes on stream
next year. As mentioned earlier, the acquisition is back-stopped initially by a US$51 million bridge loan
from BNP Paribas, to be repaid with a larger term debt facility.


ESTIMATES
2006 estimates dominated by large capital program
Having divested of the Argentine assets in Q4/05, CLL’s base production base through much of Q1/06
was approximately 600 boe/d, mainly from Battrum in Saskatchewan. The Luke acquisition was effective
March 16th, and initially contributes 2,900 boe/d, which we forecast will increase to 3,300 boe/d by year
end. The company’s total capital expenditure budget this year is $505 million, comprised of $245 million
for Luke, $64 million for the refinery, $160 million for oil sands activity, and $36 million for conventional
exploration and development spending. We forecast CLL will produce on average 3,138 boe/d this year,
and generate cash flow of $37.1 million or $0.20 per share f.d.d. We estimate year-end net debt at $141.5
million or 3.8x trailing cash flow, which is back-stopped by a combined $55 million revolving credit facility
and a $148 million term loan. We also note that CLL owns 11 million common shares of Petrolifera, or
13.3 million diluted, with no selling restrictions. Using Petrolifera’s latest price of $11.95, the market value
of CLL’s ownership is $157 million if all options are included (net of exercise price), which if sold in the
market would more than eliminate the company’s forecast net debt position.
Pod 1 forecast to start up in Q2/07
We have forecast a capital expenditure program of $150 million in 2007, and have conservatively
estimated Pod 1 of Great Divide to start-up halfway through Q2/07 (i.e. later than current company
guidance). We forecast total production to average 10,000 boe/d next year, comprised of 4,000 boe/d
from conventional assets and 6,000 b/d on average from Great Divide, producing at or close to 10,000
b/d in the second half. Our 2007 cash flow estimate is $79.9 million or $0.41 per share f.d.d. We
estimate net debt at year-end 2007 at $211.6 million, equating to 2.6x trailing cash flow, or 2.3x H2-
annualized cash flow that incorporates full production from the oil sands.
Free cash flow expected upon start-up of Pod 2
CLL anticipates developing one Pod per year for the next four years, and that cash flow from each
should be able to finance the next Pod. Also, it is important to note that the operating costs for the
SAGD process includes natural gas at market prices, but that CLL will most likely be participating in a
Syngas process, which is expected to reduce the feedstock price by over 50% from $6.00+/b to
~$3.00/b.

VALUATION
We estimate 2005 NAV at $3.24 per basic share
We estimate CLL’s net asset value (NAV) at $3.24 per basic share, utilizing the GLJ September 1, 2005
NPV PV10 pre-tax value for Great Divide, the June 30, 2005 GLJ reserve value for Luke, and have
estimated the value of CLL’s conventional reserves at year-end 2005 by assuming a conservative unit
value of $10.00/boe. In addition, we have valued the conventional undeveloped land base (CLL and
Luke) at $200/ac, and have valued the oil sands land at $300/ac. We have also assigned $60 in value
for the Montana refinery, and have included CLL’s 33% ownership in Petrolifera, which had a total
market capitalization of $411 million at Friday’s close. Based on the sum of spending and financing
activity to date this year, we estimate the company has no current net debt.

Additional upside potential exists with Great Divide and Petrolifera
We identify two additional sources of upside to the net asset value for CLL: additional value recognition
of Great Divide reserves, and additional growth from Petrolifera. Note that our $3.24/share NAV only
includes GLJ’s P+P reserves assessment of Pod 1 (i.e. 69.6 mmb) with a PV10 value of $3.25/share.
As mentioned in our reserve section, GLJ had also estimated additional probable and possible reserves
of 241.3 mmb, which if and when they are converted up, and assigning the same unit value of $3.25/b,
$millions Per share
Reserves (P+P, PV10)
CLL Conventional 25.0 0.13
Oil Sands 226.3 1.19
Luke 123.7 0.65
Total Reserves 375.0 1.98
Undeveloped land (acres)
CLL Conventional 12.0 0.06
Oil Sands 10.7 0.06
Luke 21.0 0.11
Total Land 43.7 0.23
Other Assets
Montana Refinery 60.0 0.32
Equity in Petrolifera 135.6 0.71
Total Other Assets 195.6 1.03
Estimated Current Net Debt 0.0 0.00
Total Net Asset Value 614.3 $3.24

implies additional value potential of $784 million or $4.13 per share. Second, the initial drilling success
for Petrolifera in Argentina has been nothing short of remarkable. Current production is 3,200 boe/d,
and is expected to approach 12,000 boe/d by year-end 2006, and ultimately grow to ~20,000 boe/d,
based on management’s preliminary estimates of reservoir performance. Assigning an EV/boe/d of
$30,000 to a forecast 20,000 boe/d (possibly by 2008) yields an enterprise value of $600 million
($17.44 per share) for Petrolifera, which equates to additional potential (i.e. over the current $11.95
stock price) of $60 million or $0.32 per share to CLL. This Petrolifera value growth scenario only
applies to Argentina, and ignores the potential of Peru, which could be significantly greater. Overall, we
identify additional upside over the next two years that could increase CLL’s NAV to over $7.69 per
share (with an additional upside from Peru).
Our target price of $6.30 per share is derived by applying a 1.9x P/NAV multiple to our $3.24/share
NAV. Alternately, our target price represents 50% of the additional upside from the current $4.95 stock
price to our two-year NAV of $7.69 per share. On conventional metrics, CLL’s $4.95 Friday close
represents a debt-adjusted cash flow multiple of 13.6x our 2007 estimates, versus the small cap group
average debt-adjusted multiple of 4.1x. Our $6.30 target price represents a target multiple of 16.6x our
debt-adjusted 2007 cash flow, versus the small cap average target multiple of 5.9x. The large premium
over the group average both on a current multiple and target multiple basis reflects the partial
discounting of the large potential in the Great Divide project and CLL’s ownership in Petrolifera.
RISKS
When considering our recommendation for an investment in CLL, investors should consider the risks
inherent with Small Cap/Mid Cap oil and gas producers, which include but are not limited to:
• Liquidity risk arising from investing in Small/Mid Cap companies
• CLL’s ability to raise debt or equity capital to carry out the intended spending programs
• Geologic and engineering risks associated with the finding and ultimate recovery of oil and gas
reserves in the quantities estimated in determining the company’s value
• Volatility in oil and gas prices, which may materially affect the accuracy of the forecasts
• Ability to secure drilling and completion services
• Pending EUB approval of the Great Divide oil sands project
• Operational/country risks that could impact the share price of Petrolifera
• Sector rotation risk


CONCLUSION/RECOMMENDATION
The CLL management team has spent the last two years building the company in a strategic manner to
capitalize on the high growth potential of the oil sands. That effort has come together in the past month
with the acquisition of Luke Energy to hedge CLL’s gas feedstock for its oilsands, and the acquisition of
the Montana refinery, which will hedge the heavy oil price. The final component being sought is the
pending EUB approval, which is expected shortly and should be nothing but a formality now. The
company has levered its balance sheet in the short term in order to get to this stage, but is wellcapitalized
nonetheless, and should be generating free cash flow in 2008. We anticipate additional
upside to the $7.50 to $8.00 per share range beyond the next 12 months, and are recognizing only 50%
of that in our 12-month target price. For that reason, we are initiating coverage of Connacher with
a BUY recommendation and $6.30 target price, attainment of which implies a 27% potential

[gaijin8]

Antwort auf Beitrag Nr.: 21.065.070 von XIO am 04.04.06 11:01:06

Quelle?

[XIO]

Alberta seeing booming times from oil sands

BY CLIFFORD KRAUSS THE NEW YORK TIMES
Posted on Sunday, April 2, 2006

http://www.nwanews.com/adg/Business/150601/

FORT McMURRAY, Alberta — Canada’s wild west is going corporate.

In the last big energy boom in this province, during the 1970 s, the card room at the Calgary Petroleum Club was so full of Texas oilmen that seats at the poker table were rarely freed up until well into the early morning hours.

With oil prices high again, Alberta is hopping once more — but with a twist. The skyline of Calgary, the business center of the province, is about to be altered by a large real estate project. A big new jet runway to handle the influx of oil workers is already in place, and more may be on the way. While poker is still popular, conspicuous consumption these days includes such costly indulgences as white truffles and Mercedes-Benz convertibles.

The change is reflected in the very nature of the oil business there. Once built around conventional drilling, in which independents played a major role, oil is now extracted through a heavy industrial process requiring huge capital investments.

Some of the biggest international oil companies plan to sink about $ 85. 5 billion over the next decade into developing the gooey oil sands that are at the heart of Alberta’s growing wealth and political influence. The oil sands have transformed Alberta into the epicenter of a new energybased Canadian economy that promises to be even more crucial to the United States.

The region is also taking a page from the Texas playbook. Stephen Harper from Calgary was elected in January as Canadian prime minister. His freeenterprise, tax-cutting political philosophy is closer to Houston’s than Toronto’s.

As more oil flows, economic power and population are shifting westward from the traditional manufacturing centers of Ontario and Quebec, which are lagging in comparison. The rising west is splitting the national economy, forcing industries back east to retool and reorient manufacturing to supply the growing oil economy.

In Alberta, every week seems to turn up an announcement of a new refinery, a pipeline project or a land bid. To a lesser extent, the same is happening in British Columbia and Saskatchewan.

“It’s a seesaw effect,” said Todd Hirsch, chief economist for the Canada West Foundation, a research group based in Calgary. “What’s driving Alberta, western Canada, and resources up, are what’s driving Ontario and Quebec down: the emerging Asian strength and the strength of the Canadian dollar.”

The energy companies say their investments in oil sand fields are just the beginning. The fields hold estimated reserves equivalent to as much as 175 billion barrels of oil, or more potential energy content than the oil fields of Iran and Libya combined. Oil sands production has risen to just over 1 million barrels a day today, from 400, 000 barrels in 1995. It is projected to rise to 2. 7 million barrels in 2015. By comparison, the United States consumes about 21 million barrels of oil each day, about a quarter of the world total.

EXPENSIVE PICKUPS Alberta has long been cowboy country, a cattle center in the heart of the Canadian Bible belt. But in recent years, oil has given it the fastest-growing population of any province, with people lured from elsewhere in the country and even outside Canada because salaries are growing faster than anywhere else. “We’re a big laboratory in how to absorb so much investment,” said Gwyn Morgan, executive vice chairman of EnCana, the Canadian energy company based in Calgary. “None of us could have dreamed this would happen this quickly.”

In Fort McMurray, truck and bulldozer drivers come from as far away as Newfoundland and Labrador to earn six-figure salaries. They are buying up expensive pickups as if they were toys.

The town’s population has increased to 61, 000, from 33, 000 in 1996, and housing is in such short supply that the average mobile home now sells for $ 237, 000 and couches are renting for $ 428.

The crowding and labor shortages persuaded Canadian Natural Resources Ltd. to build a jet runway long enough to accommodate Boeing 737 s to allow workers to commute to its giant new Horizon project. In Calgary, EnCana is about to build a new corporate headquarters over two square blocks that will be the biggest real estate development project in Canada in two decades.

Restaurants, wine stores, art galleries and luxury car dealers are doing a frenzied business. At a benefit auction earlier this month, one bidder paid more than $ 11, 120 to go fly-fishing with Ron A. Brenneman, president and chief executive of Petro-Canada. “I don’t see any black clouds on the horizon,” Brenneman said.

The same might be said for much of Canada. Unemployment is at a 30-year low, the Toronto stock market reached a historical high this month, and real estate is booming virtually everywhere. Oilmen there are now calling the Canadian dollar, which has climbed more than 35 percent since early 2002, a new petrocurrency.

There were only a dozen oil sands projects in Alberta a decade ago. Today there are about 60, and 55 more have been announced for the future.

TWO ECONOMIES Canada also has some losers amid the boom. Manufacturers in the east have had to retool, consolidate, and shed 180, 000 jobs in the past two years, as cheaper products enabled China to replace Canada as the top exporter of nonenergy products to the American market. Capital investment among manufacturers has decreased since 2000, although now it is recovering. “There’s no doubt we have a mild case of Dutch disease running in Canada,” said Don Drummond, senior vice president and chief economist at TD Bank, referring to the deindustrialization of the Netherlands after the discovery of North Sea gas in the 1970 s.

Particularly hurt have been companies manufacturing household appliances, electrical equipment, plastic and rubber products, textiles and paper.

At Edson Packaging Machinery Ltd., of Hamilton, Ontario, one-third of the 85 workers were laid off in 2003. By switching to American suppliers, changing its product mix and putting more emphasis on service, Edson has rebounded somewhat and increased its payroll again.

“It’s a tale of two economies,” said Robert Hattin, Edson’s president. “The resource-based economy is hot and manufacturing right now is facing challenges we haven’t seen before.”

Alberta has 10 percent of the population but directly produces 15 percent of Canada’s gross domestic product. Both numbers are likely to rise in the coming years, economists say.

[XIO]

http://www.canadianinsider.com/coReport/allTransactions.php

Apr 03/06 Mar 29/06 SETH, WAZIR, CHAND 50 - Grant of options Options 324,000 $5.040
Apr 03/06 Mar 29/06 McGregor, Stewart Donald 50 - Grant of options Options 324,000 $5.040
Mar 31/06 Mar 29/06 Bessell, Donald Hugh 50 - Grant of options Options 324,000 $5.040
Mar 31/06 Mar 29/06 Berard, Charles Watson 50 - Grant of options Options 324,000 $5.040
Mar 31/06 Mar 29/06 Marston, Stephen Adair 50 - Grant of options Options 90,000 $5.040
Mar 31/06 Mar 29/06 Evans, Colin Michael 50 - Grant of options Options 324,000 $5.040
Mar 31/06 Mar 29/06 Kennedy, Jennifer Kathleen 50 - Grant of options Options 81,000 $5.040
Mar 30/06 Mar 29/06 O'ROURKE, Timothy John 50 - Grant of options Options 510,000 $5.040
Mar 30/06 Mar 29/06 Kines, Richard Robert Joseph 50 - Grant of options Options 510,000 $5.040
Mar 30/06 Mar 29/06 Sametz, Peter D. 50 - Grant of options Options 750,000 $5.040

[XIO]

Connacher updates first quarter 2006 activity

CALGARY, Apr 17, 2006 (Canada NewsWire via COMTEX News Network) --

Connacher Oil and Gas Limited (CLL - TSX) is pleased to provide an operational update on its first quarter activities, including the Luke Energy Ltd. ("Luke") acquisition, the Montana Refining Company ("MRC") acquisition and activity and developments at its Great Divide oil sands project in northeast Alberta. The company is currently producing 3,575 boe/d, which consists of 71% natural gas production and 29% light and medium crude oil production.

Great Divide

At Great Divide Connacher drilled, logged and cored 20 wells in the first quarter 2006. Ten additional locations were prepared with surface casing set; however, weather and rig availability precluded drilling these additional locations this winter. The total number of core holes completed was considerably less than Connacher intended to drill, but it was a difficult and mild winter drilling season with a late start and an early finish for all operators in the oil sands area.

Approximately 51 square km of 3D seismic covering Pods 2, 4, 5 and extensions to Pod 1 were completed or were in the process of completion when work was suspended due to the recent arrival of caribou in the area. Seismic over regions proximate to Pod 1 will be completed after the caribou calving season is completed. This seismic will be critical for Pod 1 extension interpretation, although core holes drilled this winter already suggest that these extensions to Pod 1 do exist.

The process of interpretation and integration of 3D seismic and geology, including resource assessment, will continue throughout second quarter. Factors that will influence the time required to interpret each pod include reservoir heterogeneity or complexity, channel stratigraphy, lithology and architecture relative to original models and the desire to have tight integration of seismic data with geological data specific to each pod. These interpretations are critical to determine whether there will be sufficient quality, size and delineation to embark on SAGD development over and above Pod 1. Decisions in this regard are now more likely to occur after mid-year 2006 once the required technical assessments are completed.

Preliminary results at this time indicate that all but one core in Pod 4 have more than 15m of oilsands pay, and results at Pod 2 were considered very encouraging, based on reservoir quality and aerial extent. Pod Four is situated in the southeast corner of Connacher's main lease block and Pod 2 is located at the northeast corner. A new pod, Pod 5, located centrally on Connacher's lands, may be smaller overall than what would be required for independent development at this time. However, some form of satellite development might be possible given its proximity to Pod 1. The company is sufficiently encouraged with the results at all five pods which have been identified to date to be planning a substantial core hole and seismic program for the winter of 2007.

Connacher has responded to all final questions from the regulatory bodies which are responsible for reviewing the application to develop the Great Divide SAGD project at Pod 1. Connacher recently received a letter of concern from a First Nations group relative to its application; meetings have been held and the company is negotiating with this group to resolve the expressed concerns. Additionally, the company is developing a business solution with one of the owners of natural gas rights in the Great Divide area. Each of these sets of negotiations could be completed within a few weeks and will require final discussion with the Alberta Energy and Utility Board (EUB). These negotiations are holding up final approval of Great Divide Pod 1 at this time.

Regardless of these short-term delays, detailed engineering and design has progressed to the point where Connacher has ordered 90% of the equipment for the SAGD facility. Subject to the timing of regulatory approval, Connacher still anticipates plant startup to occur in early 2007.

Conventional Activity

At Marten Creek, Alberta, a Luke winter access property, 15 wells were drilled and 11 wells were cased in first quarter 2006. Ten wells were tested and eight were tied in to existing infrastructure and are on production. The other wells will require new infrastructure and will be 2007 projects. The new producing wells will be optimized over the course of the second quarter 2006. As a result of the success of the Marten Creek drilling, several new areas in the region will be pursued for additional exploitation and development in 2007.

Connacher is continuing to integrate the former Luke assets and experienced personnel into its operating strategy. The company is planning to drill new wells on a former Luke property at Three Hills, Alberta which will be followed by a 3D seismic-based drilling program in S.W. Saskatchewan. A total of eight locations are planned and subject to rig availability, the program is targeted for completion by the end of the second quarter 2006.

Montana Refining Company, Inc.

As previously announced on March 31, 2006, Montana Refining Company, Inc., Connacher's wholly-owned subsidiary, closed the acquisition of refining and related assets in Great Falls, Montana. The refinery processes 8,300 barrels of crude oil on a daily basis. This acquisition is considered integral to Connacher's downstream oil sands strategy. As well, it is anticipated the refinery will function as a profitable business unit in its own right. The refinery is currently on a scheduled turnaround, which is on track to be completed in early May 2006, when all units will be fully operational. The integration of this new business unit and the turnaround has proceeded very favorably, largely as a result of the strong involvement of the competent and enthusiastic Montana-based refinery personnel who remained with the operation.

Integration and expansion of the systems and personnel will continue throughout second quarter. Based on preliminary indications, demand for products and the prices anticipated to be received for gasolines, diesels and asphalts will be very strong during the upcoming summer months in 2006. With the turnaround completed by then, MRC should be operating in this peak season with a "well tuned" refinery capable of running at or near full capacity.

Connacher Oil and Gas Limited is a public Canadian crude oil and natural gas company with 191,490,659 common shares currently issued and outstanding. Its principal asset is a 100 percent interest in 110 sections (70,400 acres) of leases at its Great Divide oil sands project in northeastern Alberta. Connacher also holds conventional producing properties and reserves in the Provinces of Alberta and Saskatchewan, an 8,300 bbl/d refinery in Montana, U.S.A. and owns a 31 percent equity stake in Petrolifera Petroleum Limited (PDP - TSX), which recently announced a number of significant crude oil discoveries on its Puesto Morales/Rinconada concession located in the Neuquen Basin, Argentina.

Connacher's annual and special meeting of shareholders is scheduled to be held at 3 pm on Thursday, May 11, 2006 in the Eau Claire Room of the Westin Hotel, 320 - 4th Avenue SW, Calgary. The company anticipates releasing its first quarter results at that also.

This press release contains forward-looking statements, including statements related to the anticipated financial performance of former Luke properties and of MRC. These statements are based on current expectations that involve a number of risks and uncertainties, which could cause actual results to differ from those anticipated. These risks include, but are not limited to, risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections in relation to production, costs and expenses and health, safety and environmental risks), the risk of commodity price and foreign exchange rate fluctuations, the risks and uncertainties associated with securing the necessary regulatory approvals and financing to proceed with and complete the Great Divide project.

Due to the risks, uncertainties and assumptions inherent in forward- looking statements, prospective investors in the company's securities should not place undue reliance on these forward-looking statements. For additional information relating to the risks and uncertainties facing Connacher, refer to Connacher's 2005 Annual Report and Annual information Form which are available on SEDAR at www.sedar.com. A barrel of oil equivalent (boe), derived by converting gas to oil in the ratio of six thousand cubic feet of gas to oil, and may be misleading, particularly if used in isolation. A boe conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

SOURCE: Connacher Oil and Gas Limited

contact: Richard A. Gusella, President and Chief Executive Officer, Connacher Oil an Gas Limited, Phone: [phone], Fax: [phone], [e-mail], www.connacheroil.com
Copyright (C) 2006 CNW Group. All rights reserved.

[MONSIEURCB]

Hi zusammen! Bin ab heute auch im Boot...scheint mir ein optimaler Einstiegspunkt zu sein - und eine synergistische Ergänzung zu meinen Canwest Petroleums...auf eine goldene Zukunft! Monse

[MONSIEURCB]

Noch jemad da? Nach dem Trading halt von eben müsste der Kurs jetzt eigentlich leicht nordwärts gehen - good news!

Connacher Oil and Gas limited receives EUB Approval Letter for Great Divide Oil Sands Project
Thursday June 29, 9:21 am ET

CALGARY, June 29 /CNW/ - Connacher Oil and Gas Limited (CLL - TSX) announced today it has received a letter from the Alberta Energy and Utilities Board ("EUB/Board") which responds to the August 15, 2005 application by Connacher Oil and Gas Limited ("Connacher"), requesting approval to implement a steam-assisted gravity drainage ("SAGD") scheme for the production of bitumen from the McMurray Deposit in the Athabasca Oil Sands Area.

The letter states "After reviewing the application and all of the additional materials filed to address issues raised in respect of the application, the Board has determined that the Great Divide Oil Sands Project is in the public interest and has approved Application No. 1414169, pending an Order in Council and subject to the conditions in Approval No.10587."

This is a significant positive development for Connacher and plans to initiate on-site activity will continue to be formulated and advanced, pending the issuance of the aforementioned Order in Council. Connacher also anticipates close cooperation with Alberta Environment and Alberta Sustainable Resource Development during the final stages of the planning phase and then during the ensuing construction and operational phases of its 10,000 bbl/d Great Divide Project.

[wmuehli]

Antwort auf Beitrag Nr.: 22.340.528 von MONSIEURCB am 29.06.06 15:54:56

Guten Morgen,

eigentlich ein Meilenstein, aber wir stecken noch in den Anfängen.

Die Entwicklung zum "Großen" wird wohl noch ein wenig dauern (2-3 Jahre), habe mich da wohl verschätzt.

Naja, harren wir der weiteren Dinge, die da kommen werden, liege jedenfalls noch gut unter meinem EK.

[HappyInvestor]

Connacher Oil and Gas mit weiter guten Aussichten, Kosto hat recht

Connacher's "great divide" oil-in-place and recoverable reserves and resources up close to 50 percent over year end 2005

Source:http://biz.yahoo.com/cnw/060914/connacher_reserves_up.html?.…

[maverick [wO]]

wieder aktuell mach

[Boersenlok]

Hallo,
thread ist ja leider sanft enschlummert, egal, habe jedoch im aktuellen
börse-online heft(09/08) einen kleinen artikel über connacher gefunden...

interessante zahlen:
börsenwert: 644,9 mio US$
umsatz (2008e): 416,22 mio US$
ergebnis/aktie 2007(e): 0,24 US$
" / " 2008(e): -0,62 US$ (!)
KGV 2008 (e): -

laut dem artikel produziert der konzern täglich 10.000 tonnen öl aus ölsand
mit dem poential, die kapazitäten noch erheblich auszuweiten.

die wallstreet bewertet die aktie als zu niedrig bewertet.
in anbetracht des hohen ölpreises steht sie auf jedenfall bei mir auf der watchlist. vielleicht lässt sich ja hier wieder eine interesante diskussion eröffnen......

hier noch der link:

www.connacheroil.com/

so, mal gucken, was so geht.......

grüße
(in der hoffnung, das es ausser mir noch jemand anderes liest...)

[TinoTeletabbi]

Moin moin,

bin über connacher gestoßen, weil ich in Alberta Oilsand investiert bin. Die haben Ende 02/2008 eine News über ein Joint Venture gebracht! Vielleicht einfach mal im Alberta Tread nachlesen! Bin auch von Ölsand überzeugt, aber leider sind wir wohl fast allein auf diesem Feld...

MfG Tino T.

[wcj]

Hallo, halte Connacher als Sparbuch auf Sicht von 10 Jahren. Tausche gerne Informationen aus.

net present value:
2008:10000bpd
2009:15000
2010:20000
2011:45000 ...
bis
2030:45000bpd

Ölpreis: 100 USD/b
Produktionskosten: 38/b


15% p.a. Abzinsung

-> 3,5 Mrd USD Unternehmenswert
-> 210 Mio Aktien

NPV(100 USD/b) => 16 USD/Aktie !
NPV (80 USD/b) => 9 USD/Aktie
NPV (60 USD/b) => 2 USD/Aktie

Ich denke das sich im Jahr 2008, wenn sich die Produktionsmengen bestätigen, der wahre Wert erkannt wird. Wie gesagt für mich stimmen die Fundis also ist es eine Frage bis diese sich durchsetzen.

Freue mich über rege Rückinformation

wcj

[Boersenlok]

Hallo,

hab mal die letzte pr v. connacher mit zahlen reinkopiert... gefällt mir sehr gut. Mache z.zt. gerade brokerwechsel. sobald der durch ist, wird wohl connacher die erste aktie, die ich direkt in kanada kaufen werde. Vorallem,
wenn man die nachrichten in letzter zeit den ölpreis betreffend verfolgt hat
(spekulation 150$ - 200$ / barrell) denk ich, dass sich mit der aktie noch geld verdienen lässt. (meine meinung nur)

grüsse


PRESS RELEASE May 13, 2008

CONNACHER REPORTS FIRST QUARTER 2008 RESULTS; GREAT DIVIDE POD ONE
PRODUCTION CONTINUES TO RISE, RANGING BETWEEN 7,000 AND 8,500 BBL/D; TOTAL
PRODUCTION HAS EXCEEDED 11,000 BBL/D; MARCH 2008 CASH FLOW, IF ANNUALIZED,
WOULD EXCEED $125 MILLION AS INTEGRATED MODEL STARTS TO DELIVER RESULTS

Calgary, Alberta – Connacher Oil and Gas Limited today reported first quarter 2008 results. Of particular consequence in the
reporting period was the achievement of commerciality at Great Divide Pod One, only two months after the startup of
production at this oil sands steam assisted gravity drainage (“SAGD”) project. Accordingly, commencing March 1, 2008,
Connacher is now booking reserves, production, sales and costs in its operating results and financial statements. Previously, all
revenues and expenses related to Pod One were being capitalized. As a result, March 2008 results are the first indication of the
impact which our oil sands operation, our expanded conventional production base and our integrated approach will have on our
operations and financial results.

Revenue for March 2008 was $50 million and monthly cash flow from operations before non-cash working capital adjustments
(“cash flow”) exceeded $10.6 million. This level of revenue and cash flow generation was accomplished despite Pod One
bitumen production averaging only 5,205 bbl/d, below our ultimate design capacity of 10,000 bbl/d and below current levels
ranging between 7,000 bbl/d and 8,500 bbl/d. Total upstream sales were 8,508 boe/d, well below current levels.

March 2008 results provide the first concrete evidence of the effectiveness of our integrated strategy. Results signal our
anticipated cash generating capacity as our production volumes at Pod One ramp up to 10,000 barrels per day. Since
commerciality was achieved, our daily Pod One bitumen production has reached as high as 9,000 bbl/d. More recently, on
occasion production has been constrained as we adapt our treatment systems to higher utilization levels.

Recently, we converted two more well pairs to full SAGD production, bringing to fourteen the number of wells contributing to
our current production levels. One well pair remains to be converted. While each of the converted well pairs have been on
full SAGD for different periods, our wells have performed at or above our expectations and those of our third party reservoir
evaluator. We have had some individual wells yield daily production in excess of 1,000 bbl/d of bitumen and we are seeing
immediate daily steam/oil ratios (“SOR’s”) decline to between two and three, consistent with the high quality reservoir which
characterizes the Pod One accumulation. As a consequence, cumulative SOR’s are also declining by well and overall.

Overall Q1 2008 results were constrained by narrow heavy oil differentials, which have adversely affected refining margins
throughout the fourth quarter of 2007 and the first quarter of 2008. During the current reporting period, the narrowing of heavy
oil differentials in a rapidly rising crude oil price environment made it difficult for this division to recover rising crude oil costs
from product sales. This is particularly true for our asphalt production, which is held for sale until the paving season, when
warmer weather conditions prevail. Weak refining results were offset by the positive impact of our new oil sands production
and by much improved conventional production levels. At Marten Creek, Alberta, sales which came onstream in March 2008
approached 14 mmcf/d, which considerably exceeded our natural gas requirements to make steam at Great Divide Pod One.
Futhermore, the recognition of bitumen sales commenced in March 2008 and served to offset the impact of narrow differentials
and the previously discussed weak refining margins. Similar offsets were not available earlier in the year as bitumen
production, sales and related costs were capitalized.

We are confident of our future and believe that with continued high prices, results during the balance of the year will
substantially exceed those achieved in the first quarter 2008. We anticipate full year profitability will be achieved and that full
year results will be more aligned with or better than annualized March 2008 results. This should occur as our integrated
business model will further benefit from higher production levels throughout the remainder of 2008. Our March bitumen sales
provided an acceptable netback exceeding $30 per barrel from bitumen wellhead prices exceeding $50 per barrel. We also
anticipate that these metrics will improve as crude oil prices have risen recently and as our unit operating costs decline with
higher production at Pod One.

Connacher has increased its firm and contingent 2008 capital budget from $373 million to $391 million. The increase is to
provide additional conventional expenditures following Q1 2008 drilling success, an increase in expenditures for terminal and
other facilities at Great Divide and offset by a reduction in the provision for certain 2008 outlays at our Montana refinery,
which have been deferred until 2009.

We continue to anticipate receiving regulatory approval for our Algar 10,000 bbl/d SAGD project in the Great Divide region of
Alberta; we have preordered certain long-lead items which will assist in cost control for this project.

These Q1 2008 results will be subject to a Conference Call event at 9:00 a.m. MT May 14, 2008. To listen to or participate in
the live conference call please dial either [phone] or [phone]. A replay of the event will be available from May
14, 2008 at 11:00 a.m. MT until May 21, 2008 at 11:59 p.m. MT. To listen to the replay please dial either [phone] or
[phone] and enter the passcode 21270829 followed by the pound sign.

HIGHLIGHTS
• Great Divide Pod One achieves commerciality March 1, 2008
• Significant cash generating capacity starting to be realized
• Production has exceeds 11,000 boe/d, including 7,500 bbl/d of bitumen, with more growth anticipated as Pod One reaches
design capacity of 10,000 bbl/d
• Refining margins show improvement in March 2008 after difficult Q4 2007 and January-February 2008
• Successful winter 2008 capital program -121 core holes and 3D seismic at Great Divide and encouraging conventional
drilling results

Summary Results
Three months ended March 31 2008 2007 % Change
FINANCIAL ($000 except per share amounts)
Revenues, net of royalties $100,656 $65,923 53
Cash flow (1) 7,825 10,980 (29)
Per share, basic (1) 0.04 0.06 (33)
Per share, diluted (1) 0.03 0.05 (40)
Net earnings (loss) (1,833) 4,984 (137)
Per share, basic and diluted (0.01) 0.03 -
Property and equipment additions 115,984 109,881 6
Cash on hand 323,423 66,209 388
Working capital 287,105 24,027 1,094
Term debt 671,014 207,828 223
Shareholders’ equity 471,559 384,593 23
Total assets 1,348,098 757,205 78
OPERATING
Daily production / sales volumes
Crude oil - bbl/d 996 905 10
Bitumen – bbl/d (2) 1,773 - -
Natural gas - mcf/d 10,493 9,665 9
Barrels of oil equivalent - boe/d (3) 4,518 2,515 80
Product pricing
Crude oil - $/bbl 79.50 49.09 62
Bitumen - $/bbl (2) 53.01 - -
Natural gas - $/mcf 6.94 7.76 (11)
Barrels of oil equivalent - $/boe (3) 54.46 47.48 15
COMMON SHARES OUTSTANDING (000)
Weighted average
Basic 210,234 198,119 6
Diluted 231,510 200,008 16
End of period
Issued 210,277 198,218 6
Fully diluted 250,166 216,606 15

(1) Cash flow and cash flow per share do not have standardized meanings prescribed by Canadian generally accepted accounting principles (“GAAP”) and
therefore may not be comparable to similar measures used by other companies. Cash flow is calculated before changes in non-cash working capital,
pension funding and asset retirement expenditures. The most comparable measure calculated in accordance with GAAP would be net earnings. Cash
flow, commonly used in the oil and gas industry, is reconciled with net earnings on the Consolidated Statements of Cash Flows and in the accompanying
Management’s Discussion & Analysis. Management uses these non-GAAP measurements for its own performance measures and to provide its
shareholders and investors with a measurement of the company’s efficiency and its ability to internally fund future growth expenditures.
(2) The recognition of bitumen sales from Great Divide Pod One commenced March 1, 2008, when it was declared “commercial”. Prior thereto, all operating
costs, net of revenues, were capitalized. Daily production/sales volumes for the month of March averaged 5,205 bbl which equates to 1,773 bbl/d for the
first quarter of 2008.
(3) All references to barrels of oil equivalent (boe) are calculated on the basis of 6 mcf:1 bbl. Boes may be misleading, particularly if used in isolation. This
conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the
wellhead.

LETTER TO SHAREHOLDERS

Overview

Connacher achieved improved operational results during the first quarter of 2008. The highlight was the ramp-up of bitumen
production from our steam assisted gravity drainage or SAGD operation at Pod One of our Great Divide oil sands project.
During the quarter, 12 out of 15 well pairs were converted over at different times to full SAGD injection and production. This
followed a pre-heat and semi-SAGD phase during the latter part of 2007 and into the immediate pre-production phase.
Commerciality was achieved effective March 1, 2008. As a result, revenues and associated costs for Pod One are now being
recorded in the company’s financial accounts.

Our cash flow in March 2008 exceeded $10 million, or $125 million if annualized, indicating the tremendous cash generating
capacity which the company now possesses, even though Pod One was only operating at around 50 percent of capacity. In
March 2008, daily bitumen production averaged 5,205 bbl/d as volumes were being ramped up towards the plant’s rated
capacity of 10,000 bbl/d. Production ramp-up throughout the quarter exceeded internal estimates. If current prices are
maintained it is evident that further growth in revenue, cash flow and profitability is anticipated and should be more readily
apparent in the remaining quarters of 2008.

We also note the company was also able to achieve significant growth of its conventional production with new gas production
and sales at Randall. This followed a well organized and efficient facilities construction program in the region during January
and February 2008. Conventional production in March 2008 averaged 3,303 boe/d, including approximately 14 mmcf/d of
natural gas with new Randall volumes coming onstream. Total sales were 8,508 boe/d in March 2008 and averaged 4,518 boe/d
for the quarter.

On April 4, 2008, Connacher announced its production had surpassed 10,600 boe/d as bitumen sales exceeded 7,000 bbl/d and
conventional volumes reached 3,600 boe/d, both record levels of production. Subsequently, bitumen sales have surpassed this
level and further increases will accompany the conversion of the remaining three SAGD well pairs. Further identifiable gains at
Great Divide Pod One are anticipated to result in sales approaching 14,000 boe/d by year end 2008.

These operational advances were masked to some extent in the quarter by a difficult start to the year for our refining and
marketing activity in Montana. High oil prices during a low margin season coupled with narrowing heavy crude oil
differentials to WTI impaired results during January and February 2008 in this division, although a marked turnaround was in
evidence by March 2008.

We had an active capital program during the first quarter of 2008, with outlays exceeding $114 million. Emphasis was placed
on core hole drilling and 3D seismic at Great Divide and core hole drilling and 2D seismic at Halfway Creek on our oil sands
leases. We also experienced considerable drilling success in our conventional program. We are excited about the indicated
results, which will be more fully evaluated in our mid-year reserve report update.

Overall we anticipate 2008 will be a record year for Connacher as its reported financial and operating results benefit from
higher volumes and high prices, as well as improved returns in our refining division throughout the summer. We also
anticipate mid-year approval of our second 10,000 bbl/d Algar Project at Great Divide so we can proceed with our already-
financed construction program.

Great Divide

We had a very productive first quarter 2008 at Great Divide Pod One. We commenced the conversion of our 15 SAGD well
pairs to full injection and production early in the year, overcoming extremely cold weather during the early stages of this
conversion process, which was conducted in a systematic manner to yield efficient results. Our ramp up proceeded at
unprecedented rates, ahead of anticipated levels. We were able to report improved production on a regular basis. Most recently
production has ranged between 7,000 bbl/d and 8,500 bbl/d of bitumen. Well productivity and steam oil ratios have been
improving on a consistent basis, with individual wells exceeding 1,000 bbl/d on occasion and steam oil ratios (“SORs”) below
3:1 early in well lives. We are optimistic we can achieve targeted design volumes or higher on a near term basis with project
SORs approaching 2.6 or better.

We have encountered some start up issues as is customary for a project of this type, but it is a credit to our operating staff that
issues have been identified and resolved fairly quickly. Our economics were respectable in this startup phase when operating
costs are spread over smaller volumes and diluent costs were high. In March 2008, we received an average dilbit sales price of
$77.24/bbl, which after deduction of the cost of diluent, operating costs and transportation charges, translates into a calculated
wellhead netback for bitumen of approximately $53.01 per barrel. We anticipate this can further improve as economies of full
scale operation at design capacity are achieved, with fixed costs spread over a broader production base. Even with these costs,
volumes of 10,000 bbl/d, if and when achieved, would translate into annualized net operating income exceeding $100 million
for Pod One alone. This would be supplemented by our anticipated conventional and refining operating income.

We are confident our high quality reservoir and our operating strategy in the oil sands will afford us the opportunity to plan
continued expansion in the oil sands with growing confidence. We were most encouraged by the indicated results of our 2008
winter core hole program and believe they will expand and upgrade our reserve and resource base when we receive our reserve
report update later in the year. We also await regulatory approval of our Algar project, which, based on previous experience, is
anticipated prior to mid-year. Financing for this project is in place and we have preordered and acquired considerable
equipment in anticipation of commencement of construction this summer.

Our longer term objective or vision is to systematically develop our productive capacity in the oil sands to 50,000 bbl/d by
2015. Employing our integrated strategy, we also anticipate increasing our upstream natural gas productive capacity to 50
mmcf/d within this timeframe, to continue to hedge our significant operating cost component and thus keep our integrated
netbacks at higher levels than if we were solely a bitumen producer. Also, we are actively examining the merits of expanding
our refining capacity, initially to approximately 35,000 bbl/d and ultimately in lockstep with our upstream bitumen production
growth to 50,000 bbl/d. In management’s opinion, our 50-50-50 goal by 2015 is achievable at minimal dilution and we are
pursuing this vision with all available energy and commitment.

Conventional and Refining

We continued to grow our conventional natural gas production and are now producing about 150 percent of our Pod One
requirements, so we have a solid head start on Algar requirements. This added production is derived from exploratory and
development drilling success achieved during 2007 and in 2008. We also completed facilities at Randall under budget and
ahead of schedule, thus bringing these volumes onstream with attendant earlier revenue and cash flow. Facilities at Three Hills
were also completed and our core area in this region was expanded with successful new drilling.

As indicated, our Montana Refining division encountered economic challenges during January and February 2008 before
conditions improved in March. This reflected the rapid and considerable increase in crude purchase costs due to rising crude
oil prices and a narrowing of the heavy crude oil differential to WTI in a weak season for refined products, particularly asphalt.
This division was a major cash flow contributor in 2007 and we anticipate market conditions will improve as the year
progresses. Our capital program at our Great Falls refinery is currently focused on production of ultra low sulphur diesel
(“ULSD”) to meet regulatory requirements. Serious evaluation of the merits of a 25,000 bbl/d expansion is also under review,
including an examination of financing alternatives. A decision to proceed on this expansion project will be made at a later date.

Other

Our property and equipment additions in the first quarter 2008 totaled $116 million, including $83 million on our overall oil
sands operations – core holes, facilities, seismic, preordering items for Algar and capitalized costs. Approximately $30 million
was invested in our conventional crude oil and natural gas properties and the balance was invested in our refinery. While in
excess of cash flow, our cash balances to fund Algar remain strong and we also have a significant unutilized credit facility
available for our operations. While we have considerable capital expenditures ahead of us, especially with possible refinery
expansion and pipeline construction to consider, we will pursue these objectives, if finalized, in a manner that maximizes
shareholder returns.

We are gratified by the recent stock market recognition of our improving fundamentals and financial results and cash
generating capacity, as manifested in an improved price for our common shares. We have a solid institutional and retail
shareholder base and management and directors remain significant stakeholders of the company, with a solid commitment to its
growth and well-financed expansion. We have put together a solid, experienced and qualified management group in recent
years and we believe our technical expertise, especially in respect of SAGD operations, is unparalleled for a company of our
size.

We operate with a small compact group of professionals who should be proud of their collective accomplishments. We look
forward to reporting our progress to you, our shareholders, as the ensuing quarters of 2008 unfold.

Forward Looking Information
This press release contains forward-looking information including anticipated increases in reserves and resources as a result of the 2008
winter core drilling program, expectations of future production, revenues, cash flow, profitability and capital expenditures, anticipated
reductions in operating costs as a result of optimization of certain operations, development of additional oil sands resources (including
receipt of regulatory approvals in respect of Algar and the timeline for construction of Algar), expansion of current conventional oil and gas
and refining operations and evaluation of future transportation alternatives and implementation thereof and anticipated sources of funding
for capital expenditures. Forward looking information is based on management’s expectations regarding future growth, results of operation,
production, future capital and other expenditures (including the amount, nature and sources of funding thereof), plans for and results of
drilling activity, environmental matters, business prospects and opportunities. Forward-looking information involves significant known and
unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not
limited to: the risks associated with the oil and gas industry (e.g., operational risks in development, exploration and production; delays or
changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve and resource
estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental
risks), and the risk of commodity price and foreign exchange rate fluctuations, and risks and uncertainties associated with securing the
necessary regulatory approvals and financing to proceed with the continued expansion of the Great Divide Project at Algar and other
regions and expansion of the company’s refinery in Great Falls, Montana. These risks and uncertainties are described in detail in
Connacher’s Annual Information Form for the year ended December 31, 2007, which is available at www.sedar.com. Annualized cash flow
and net operating income based on March financial results is provided for illustrative purposes to show the effect of the Corporation’s
integrated model following the achievement of commerciality at Great Divide Pod One. Actual annual cash flow and net operating revenue
will vary from the annualized estimate provided and such variations may be material. Although Connacher believes that the expectations in
such forward-looking information are reasonable, there can be no assurance that such expectations shall prove to be correct. The
Corporation assumes no obligation to update or revise the forward-looking information to reflect new events or circumstances, except as
required by law.

For further information, contact:
Richard A. Gusella
President and Chief Executive Officer

OR

Grant D. Ukrainetz
Vice President, Corporate Development

Phone: [phone] Fax: [phone]
[e-mail] Website: www.connacheroil.com














Suite 900, 332 – 6th Avenue S.W.
Calgary, Alberta T2P 0B2
Telephone: [phone] Facsimile: [phone]




MANAGEMENT’S DISCUSSION AND ANALYSIS

The following is dated as of May 13, 2008 and should be read in conjunction with the unaudited consolidated financial
statements of Connacher Oil and Gas Limited (“Connacher” or the “company”) for the three months ended March 31, 2008 and
2007 as contained in this interim report and the MD&A, and audited consolidated financial statements for the years ended
December 31, 2007 and 2006 as contained in the company’s 2007 annual report. All of these consolidated financial statements
have been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”) and are presented in
Canadian dollars. This MD&A provides management’s view of the financial condition of the company and the results of its
operations for the reporting periods.

Additional information relating to Connacher, including Connacher’s Annual Information Form is on SEDAR at
www.sedar.com.

FORWARD-LOOKING INFORMATION

This quarterly report, including the Letter to Shareholders, contains forward-looking information including but not limited to
anticipated increases in reserves and resources as a result of the 2008 winter core hole drilling program, expectations of future
production, revenues, cash flow, profitability and capital expenditures, anticipated reductions in operating costs as a result of
optimization of certain operations, development of additional oil sands resources (including receipt of regulatory approvals in
respect of Algar and timeline for construction of Algar), expansion of current conventional oil and gas and refining operations,
evaluation of future transportation alternatives and implementation thereof and anticipated sources of funding for capital
expenditures. Forward looking information is based on management’s expectations regarding future growth, results of
operation, production, future capital and other expenditures (including the amount, nature and sources of funding thereof),
plans for and results of drilling activity, environmental matters, business prospects and opportunities. Forward-looking
information involves significant known and unknown risks and uncertainties, which could cause actual results to differ
materially from those anticipated. These risks include, but are not limited to: the risks associated with the oil and gas industry
(e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or
development projects or capital expenditures; the uncertainty of reserve and resource estimates; the uncertainty of estimates
and projections relating to production, costs and expenses, and health, safety and environmental risks), the risk of commodity
price and foreign exchange rate fluctuations, risks and uncertainties associated with securing and maintaining the necessary
regulatory approvals and financing to proceed with the continued expansion of the Great Divide Project and of the company’s
refinery in Great Falls, Montana. These risks and uncertainties are described in detail in Connacher’s Annual Information Form
for the year ended December 31, 2007, which is available at www.sedar.com. . Annualized cash flow and net operating income
based on March financial results is provided for illustrative purposes to show the effect of the Corporation’s integrated model
following the achievement of commerciality at Great Divide Pod One. Actual annual cash flow and net operating revenue will
vary from the annualized estimate provided and such variations may be material. Although Connacher believes that the
expectations in such forward-looking information are reasonable, there can be no assurance that such expectations shall prove
to be correct. The forward-looking information included in this quarterly report are expressly qualified in their entirety by this
cautionary statement. The forward-looking information included in this quarterly report is made as of May 13, 2008 and
Connacher assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances,
except as required by law.

FINANCIAL AND OPERATING REVIEW

UPSTREAM NETBACKS ($000)
For the three months ended March 31
2008 Oil Sands (1) Crude Oil Natural Gas Total
Gross revenues (2) $17,150 $7,206 $6,633 $30,989
Diluent purchased (3) (8,103) (8,103)
Transportation costs (494) - - (494)
Production revenue 8,553 7,206 6,633 22,392
Royalties (86) (1,815) (1,162) (3,063)
Operating costs (3,403) (1,060) (1,426) (5,889)
Total netback (4) $5,064 $4,331 $4,045 $13,440




2007
Gross revenues $ 3,997 $ 6,750 $10,747
Diluent purchased - - -
Production revenue 3,997 6,750 10,747
Royalties (939) (1,601) (2,540)
Operating costs (876) (1,056) (1,932)
Total netback $ 2,182 $ 4,093 $6,275

(1) In the first quarter of 2008, Connacher completed the conversion of a majority of its fifteen horizontal well pairs to production status at Great Divide Pod
One and processed increasing levels of bitumen through its facility. This provided the company with the necessary confidence that this first oil sands
project could economically produce, process and sell bitumen on a continuous basis. Therefore, effective March 1, 2008 Connacher declared it to be
“commercial”. As a result, the company discontinued the capitalization of all pre-operating costs, moved accumulated capital costs into the full cost pool,
commenced the depletion of these costs, and began reporting Pod One production and operating results as part of the oil and gas reporting segment.
(2) Bitumen produced at Great Divide Pod One is mixed with purchased diluent and sold as “dilbit”. Diluent is a light hydrocarbon that improves the
marketing and transportation quality of bitumen. In the financial statements Upstream Revenues represent sales of dilbit, crude oil and natural gas, net of
royalties; and Upstream Operating Costs include the cost of purchased diluent.
(3) Diluent volumes purchased and sold have been deducted in calculating production revenue and production volumes sold.
(4) Total netbacks, by product, are calculated by deducting the related diluent, transportation, field operating costs and royalties from revenues. Netbacks on
a per-unit basis are calculated by dividing related production revenue, costs and royalties by production volumes. Netbacks do not have a standardized
meaning prescribed by GAAP and, therefore, may not be comparable to similar measures used by other companies. This non-GAAP measurement is a
useful and widely used supplemental measure of the company’s efficiency and its ability to fund future growth through capital expenditures. Netbacks are
reconciled to net earnings below.

UPSTREAM SALES AND PRODUCTION VOLUMES
For the three months ended March 31
2008 2007 % Change
Dibit sales (1) 2,440 bbl/d - -
Diluent purchased (1) (667) bbl/d - -
Bitumen produced and sold (1) 1,773 bbl/d - -
Crude oil produced and sold 996 bbl/d 905 bbl/d 10
Natural gas produced and sold 10,493 mcf/d 9,665 mcf/d 9
Total 4,518 boe/d 2,515 boe/d 80
(1) Since declaring Great Divide Pod One “commercial” effective March 1, 2008, dilbit sales averaged 7,164 bbl/d in March, or 2,440 bbl/d in the first
quarter of 2008; diluent purchases averaged 1,959 bbl/d in March, or 667 bbl/d for the quarter; and bitumen production and sales volumes averaged 5,205
bbl/d in March, or 1,773 bbl/d for the first quarter of 2008.

UPSTREAM NETBACKS PER UNIT OF PRODUCTION
For the three months ended March 31
2008
Bitumen
($ per bbl) Crude Oil
($ per bbl) Natural Gas
($ per mcf) Total
($ per boe)
Production revenue
Royalties (0.53) (20.03) (1.22) (7.45)
Operating costs (21.09) (11.69) (1.49) (14.32)
Upstream netback $31.39 $47.78 $4.23 $32.69


2007 Bitumen
($ per bbl) Crude Oil
($ per bbl) Natural Gas
($ per mcf) Total
($ per boe)
Production revenue
Royalties - (11.53) (1.84) (11.22)
Operating costs - (10.76) (1.21) (8.54)
Upstream netback - $26.80 $4.71 $27.72

In the first quarter of 2008, bitumen, crude oil, and natural gas revenues were up 188 percent to $31 million from $10.7 million
in the first quarter of 2007. This was primarily due to increased production and sales volumes in 2008. Dilbit sales of $17.2
million for the month of March, since declaring Pod One “commercial”, contributed most of the $20 million increase. A 10
percent increase in crude oil production and a 62 percent increase in crude oil pricing contributed the balance of the increase in
revenues. Although natural gas production and sales volumes increased nine percent over the prior year period, natural gas
selling prices were lower this year ($6.94/mcf) than last year ($7.76/mcf), primarily due to the $816,000 unrealized mark-to-
market loss on the gas collar sustained in 2008.

In the first quarter of 2008, the company entered into a “costless collar” contract with a third party to receive a minimum of US
$7.50 per mmbtu and a maximum of US $10.05 per mmbtu on a notional quantity of 5,000 mmbtu per day of natural gas sold
between April 1, 2008 and October 31, 2008. This transaction was not meant to speculate on future natural gas prices, but
rather to protect the downside risk to the company’s cash flow and the lending value of its assets, which is considered very
important during a period of rapid growth with significant capital expenditures.

Royalties represent charges against production or revenue by governments and landowners. Royalties in the first quarter of
2008 were $3.1 million compared to $2.5 million in the first quarter of 2007. From year to year, royalties can change based on
changes in the product mix, the components of which are subject to different royalty rates. Additionally, royalty rates typically
escalate with increased product prices. The most notable change in royalties this period came as a result of new bitumen
production and sales volumes reported from March 1, 2008. In 2008, royalties on bitumen production are payable at the rate of
one percent of the bitumen selling price. As a result of this new bitumen production and increased crude oil revenue, royalties
increased by $523,000. However, the low bitumen royalty rate reduced the company’s average royalty rate from 24 percent to
14 percent of production revenues, or from $11.22 per boe to $7.45 per boe.

In the first quarter of 2008 upstream diluent purchases and operating costs of $14 million were $12.1 million (624 percent)
higher than in the same prior year period, primarily due to diluent purchases of $8.1 million in 2008 related to the
commencement of oil sands bitumen production and dilbit sales, effective from March 1, 2008. Bitumen produced at Great
Divide Pod One is mixed with purchased diluent and sold as “dilbit.” Diluent is a light hydrocarbon that improves the
marketing and transportation quality of bitumen. For the reported volumes, diluent purchased represented approximately 27
percent of the dilbit barrel sold; bitumen the remaining 73 percent. It is anticipated that less diluent will be necessary when oil
sands production and handling operations are optimized and higher volumes are processed. The price of diluent is influenced
by supply and demand and in the current period, they were at historic high levels.

Excluding diluent purchases, upstream field operating costs averaged $14.32 per boe produced and sold in the first quarter of
2008, compared to $8.54 per boe produced and sold in the same prior year period. The increase primarily reflects costs
associated with new bitumen production. Bitumen field operating costs of $3.4 million for March 2008 comprise natural gas
($1.9 million for 7.2 mmcf/d, averaging $8.65/mcf), personnel, power, chemicals and other costs, averaging $21.09 per bbl of
bitumen produced and sold. As a significant portion of these costs are fixed, it is anticipated that this per unit operating cost
will decline as the company increases bitumen production to its design capacity of 10,000 bbl/d in 2008.

Transportation costs of $494,000 represent the cost of trucking a small portion of the company’s oil sands sales to market, as a
majority of its sales were priced “net of transportation.”

Netbacks are a widely used industry measure of a company’s efficiency and its ability to internally fund its growth. The
company’s overall upstream netback of $32.69 per produced boe (an 18 percent increase over the same 2007 period) is
significantly affected by its oil sands production, which had a netback of $31.39 per bitumen barrel produced. Given its early
stage of development and anticipating more operating efficiencies will be realized, particularly with expected higher
production volumes, the company is satisfied with its oil sands results at this time.

Reconciliation of Netback to Net Earnings

For the three months ended March 31 2008 2007
($000, except per unit amounts) Total Per boe Total Per boe
Upstream netback as above $13,440 $32.69 $6,275 $27.72
Interest income 831 2.02 120 0.53
Refining margin – net 506 1.23 11,198 49.47
General and administrative (3,066) (7.46) (3,584) (15.83)
Stock-based compensation (1,516) (3.69) (2,946) (13.02)
Finance charges (4,431) (10.78) (446) (1.97)
Foreign exchange (loss) gain (1,892) (4.60) 1,702 7.52
Depletion, depreciation and accretion (7,464) (18.15) (7,357) (32.50)
Income taxes 1,346 3.27 (3,878) (17.13)
Equity interest in Petrolifera earnings and dilution gain 413 1.00 3,900 17.23
Net earnings (loss) $(1,833) $(4.47) $4,984 $22.02

DOWNSTREAM REVENUES AND MARGINS

The Montana refinery is subject to a number of seasonal factors which typically cause product sales revenues to vary
throughout the year. The refinery’s primary asphalt market is for paving roads which is predominantly a summer demand.
Consequently, prices and sales volumes for our asphalt tend to be higher in the summer and lower in the colder seasons. During
the winter, most of the refinery’s asphalt production is stored in tankage for sale in the subsequent summer months. Seasonal
factors also affect sales revenues for gasoline (higher demand in summer months) as well as distillate and diesel fuels (higher
winter demand). As a result, inventory levels, sales volumes and prices can be expected to fluctuate on a seasonal basis.

In the first quarter of 2008, refining industry margins narrowed further than was experienced in the fourth quarter of 2007. This
has been mainly attributed to crude oil costs rising faster than the selling prices of refined products and by a narrowing of the
heavy : light oil pricing differential which also influences heavy refining profit margins.

In the first quarter of 2008, the company’s refining revenues ($71.9 million) were lower than in the fourth quarter of 2007
($75.7 million) due to restricted asphalt sales, but were higher than the first quarter of 2007 ($57.6 million) due to generally
higher refined product prices. Refining costs of sales in the first quarter of 2008 ($71.4 million) were higher than in the fourth
quarter of 2007 ($70.9 million) and in the first quarter of 2007 ($46.4 million) due to higher crude oil costs.

Refinery throughput - three months ended Mar 31, 2007 June 30, 2007 Sept 30, 2007 Dec 31, 2007 Mar 31, 2008
Crude charged (bbl/d) (1) 9,621 9,248 9,400 9,610 9,830
Refinery production (bbl/d) (2) 10,634 10,085 10,478 10,578 11,081
Sales of produced refined products (bbl/d) 7,777 9,753 12,906 10,629 7,408
Sales of refined products (bbl/d)(3) 8,254 10,735 13,447 11,014 7,902
Refinery utilization (4) 101% 97% 100% 101% 104%
(1) Crude charged represents the barrels per day of crude oil processed at the refinery.
(2) Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks.
(3) Includes refined products purchased for resale.
(4) Represents crude charged divided by total crude capacity of the refinery.

Feedstocks - three months ended Mar 31, 2007 June 30, 2007 Sept 30, 2007 Dec 31, 2007 Mar 31, 2008
Sour crude oil 92% 93% 91% 93% 92%
Other feedstocks and blends 8% 7% 9% 7% 8%
Total 100% 100% 100% 100% 100%

Revenues and Margins ($000)
Refining sales revenue $57,596 $84,628 $95,093 $75,733 $71,899
Refining - crude oil and operating costs 46,398 66,480 81,107 70,863 71,393
Refining margin $11,198 $18,148 $13,986 $4,870 $506
Refining margin 19.4% 21.4% 14.7% 6.4% 0.7%

Sales of Produced Refined Products (Volume %)
Gasolines 52% 40% 31% 35.3% 47.2%
Diesel fuels 27% 18% 12% 15.8% 26.6%
Jet fuels 6% 5% 6% 6.2% 8.1%
Asphalt 11% 33% 48% 38.9% 12.7%
LPG and other 4% 4% 3% 3.8% 5.4%
Total 100% 100% 100% 100% 100%

Per Barrel of Produced Refined Product Sold
Refining sales revenue $77.53 $86.63 $76.87 $74.74 $99.99
Less: refining - crude oil purchases and operating costs 62.46 68.05 65.56 69.93 99.28
Refining margin $15.07 $18.58 $11.31 $4.81 $0.71

INTEREST AND OTHER INCOME

In the first quarter of 2008, the company earned interest of $831,000 (March 31, 2007 - $120,000) on excess funds invested in
secure
short-term investments. The company has not invested in asset-based commercial paper investments.

GENERAL AND ADMINISTRATIVE EXPENSES

In the first quarter of 2008, general and administrative (“G&A”) expenses were $3.1 million compared to $3.6 million in the
first quarter of 2007, a decrease of 14 percent, as the company capitalized more costs in the current period ($1.9 million) than
in the first quarter of 2007 ($290,000) due to more of these expenses for personnel engaged in this expanded capital program.

STOCK BASED COMPENSATION

The company recorded non-cash stock-based compensation charges in the respective periods as follows:

Three months ended March 31
($000) 2008 2007
Charged to G&A expense $1,516 $2,946
Capitalized to property and equipment 798 546
$2,314 $3,492

The reduction from the prior is due to fewer options being granted and a lower share price.

FINANCE CHARGES

Finance charges include interest expensed relating to the Convertible Debentures and amounts drawn on revolving lines of
credit, standby fees associated with the company’s undrawn lines of credit, fees on letters of credit issued, and a portion of the
Senior Notes interest expense attributable to Great Divide Pod One since it was declared commercial, effective March 1, 2008.
Finance charges also include non-cash accretion charges with respect to the Convertible Debentures and a portion to the Senior
Notes.

Expensed finance charges of $4.4 million in the first quarter of 2008 compared to $446,000 reported in the first of quarter of
2007. These charges increased primarily due to the issuance of the Convertible Debentures and Senior Notes in 2007.

FOREIGN EXCHANGE GAINS AND LOSSES

In the first quarter of 2008, the company recorded a foreign exchange loss of $1.9 million with respect to the translation of its
US dollar denominated indebtness and its currency swap. An unrealized foreign exchange gain of $1.7 million was recorded in
the first quarter of 2007 upon translating it US dollar denominated indebtness.

DEPLETION, DEPRECIATION AND ACCRETION (“DD&A”)

Depletion expense is calculated using the unit-of-production method based on total estimated proved reserves. Refining
properties and other assets are depreciated over their estimated useful lives. Effective March 1, 2008 Pod One’s accumulated
capital costs were added to the depletion pool and are being depleted from that date. DD&A in the first quarter of 2008 was
$7.5 million, a one percent increase from last year due to higher production volumes and increased capital costs, offset
somewhat by the benefit of a longer oil sands reserve life related to Pod One. Depletion equates to $13.31 per boe of
production compared to $25.12 per boe last year, reflecting the benefit of adding substantial Pod One proved reserves to the
depletion calculation.

Capital costs of $125.3 million (March 31, 2007 – $239 million) related to oil sands projects currently in the pre-production
stage, and undeveloped land acquisition costs of $14.9 million (2007 – $16.3 million) were excluded from the depletion
calculation. Future development costs of $253.1 million (2007 - $3.2 million) for proved undeveloped reserves were included
in the depletion calculation.

Included in DD&A is an accretion charge of $422,000 (March 31, 2007 - $191,000) in respect of the company’s estimated
asset retirement obligations. These charges will continue in future years in order to accrete the currently booked discounted
liability of $24 million to the estimated total undiscounted liability of $44.3 million over the remaining economic life of the
company’s oil sands, crude oil and natural gas properties.

At March 31, 2008, the recoverable value of the company’s productive crude oil, oil sands and natural gas assets exceeded its
carrying value and, therefore, no ceiling test writedown was required.

INCOME TAXES

The income tax recovery of $1.3 million in the first three months of 2008 includes a current income tax provision of $817,000,
principally related to Canadian capital and other taxes and a future income tax recovery of $2.1 million reflecting the benefit of
increased tax pools during the period.

At March 31, 2008 the company had approximately $79 million of non-capital losses which do not expire before 2028, $191
million of capital losses which do not have an expiry date, $480 million of deductible resource pools and $34 million of
deductible financing costs.

EQUITY INTEREST IN PETROLIFERA PETROLEUM LIMITED (“PETROLIFERA”)

Connacher accounts for its 26 percent equity investment in Petrolifera on the equity method basis of accounting. Connacher’s
equity interest share of Petrolifera’s earnings in the first three months of 2008 was $413,000 (March 31, 2007 - $3.9 million).

NET EARNINGS

In the first three months of 2008 the company reported a loss of $1,833,000 ($0.01 loss per basic and diluted share outstanding)
compared to earnings of $5.0 million or $0.03 per basic and diluted share for the first three months of 2007.

SHARES OUTSTANDING

For the first three months of 2008, the weighted average number of common shares outstanding was 210,234,346 (2007 –
198,119,130) and the weighted average number of diluted shares outstanding, as calculated by the treasury stock method, was
210,234,346 (2007 – 200,007,743).

As at May 12, 2008, the company had the following equity securities issued and outstanding:

• 210,525,166 common shares;
• 19,471,893 share purchase options; and
• 392,705 share units (“SUs”) under the non-employee director share awards plan.

Additionally, 20,010,000 common shares are issuable upon conversion of the Convertible Debentures. Details of the exercise
provisions and terms of the outstanding options are noted in the consolidated financial statements, included in this interim
report.

LIQUIDITY AND CAPITAL RESOURCES

At March 31, 2008, the company had working capital of $287.1 million, including $323.4 million of cash on hand. Of this
amount $66 million was restricted in an interest reserve account related to the Senior Notes.

At March 31, 2008 the company also had approximately $181 million available to be drawn on its five-year term Revolving
Credit Facilities, as approximately $19 million was used to secure letters of credit primarily for its crude oil purchase activity
associated with the refining business. Available cash, cash flow and funds available under its Revolving Credit Facilities are
anticipated to be sufficient to fully fund the company’s capital program in 2008 and to complete Algar in 2009. A significant
part of the company’s capital program is discretionary and may be expanded or curtailed based on drilling results and the
availability of capital. This is reinforced by the fact that Connacher operates most of its wells and holds a very high working
interest in all its properties, providing the company with operational and timing controls.

Cash flow and cash flow per share do not have standardized meanings prescribed by GAAP and therefore may not be
comparable to similar measures used by other companies. Cash flow includes all cash flow from operating activities and is
calculated before changes in non-cash working capital, pension funding and asset retirement expenditures. The most
comparable measure calculated in accordance with GAAP is net earnings. Cash flow is reconciled with net earnings on the
Consolidated Statement of Cash Flows and below.

Cash flow per share is calculated by dividing cash flow by the calculated weighted average number of shares outstanding.
Management uses this non-GAAP measurement (which is a common industry parameter) for its own performance measure and
to provide its shareholders and investors with a measurement of the company’s efficiency and its ability to fund future growth
expenditures.

The company’s only financial instruments are cash, restricted cash, accounts receivable and payable, amounts due from
Petrolifera, the Revolving Credit Facilities, the Convertible Debentures, the Senior Notes and the cross-currency swap. The
company maintains no off-balance sheet financial instruments.

As the Senior Notes are denominated in US dollars, there is a foreign exchange risk associated with their repayment using
Canadian currency. This risk is partially mitigated by the cross currency swap.

The natural gas costless collar is intended to mitigate some downside natural gas pricing risk and, therefore, protect the risk of
reduced cash flow and the risk of reductions to the lending value of its banking facilities, which is considered particularly
important in a time of rapid growth with significant capital expenditure.

Connacher’s capital structure is composed of:
As at
March 31, 2008 As at
December 31, 2007
($000)
Long term debt (1) $671,014 $ 664,462
Shareholders’ equity
Share capital, contributed surplus and equity component 433,530 444,086
Accumulated other comprehensive loss (10,127) (13,636)
Retained earnings 48,156 49,989
Total $1,142,573 $ 1,144,901

Debt to book capitalization (2) 59% 58%
Debt to market capitalization (3) 49% 44%

(1) Long-term debt is stated at its carrying value, which is net of fair value adjustments, original issue discounts, transaction costs and the Convertible
Debentures’ equity component value.
(2) Calculated as long-term debt divided by the book value of shareholders’ equity plus long-term debt.
(3) Calculated as long-term debt divided by the period end market value of shareholders’ equity plus long-term debt.

Connacher had a high calculated ratio of debt to capitalization at March 31, 2008. This is due to pre-funding the full cost of
Algar in 2007, through the issuance of US $600 million of Senior Notes. As at March 31, 2008, the company’s calculated ratio
of net debt (long-term debt, net of cash on hand) to book capitalization was 30 percent and the percentage of net debt to market
capitalization was 25 percent.

In the first quarter of 2008, Pod One, the company’s first oil sands facility, had commenced commercial operations. It is
anticipated that Pod One will attain its design capacity of 10,000 bbl/d of bitumen production during 2008. This is expected to
result in substantially higher levels of revenue and cash flow for the company. This cash flow, together with cash deposited in a
debt service account, are anticipated to be more than sufficient to fund the company’s interest costs in 2008.

Reconciliation of net earnings to cash flow from operations before working capital and other changes:






Three months ended March 31
2008 2007
($000s)
Net earnings (loss) $(1,833) $4,984
Items not involving cash:
Depletion, depreciation and accretion 7,464 7,357
Stock-based compensation 1,516 2,946
Finance charges –non-cash portion 1,249 -
Future employee benefits 113 130
Future income tax provision (recovery) (2,163) 1,165
Foreign exchange (gain) loss 1,892 (1,702)
Equity interest in Petrolifera earnings (413) (3,900)
Cash flow from operations before working capital and other $7,825 $10,980

In the first quarter of 2008, cash flow was $7.8 million ($0.04 per basic and $0.03 per diluted share), 29 percent lower than the
$11 million reported ($0.06 per basic and $0.05 per diluted share) for the first three months of 2007, primarily due to lower
refining margins compared to the first quarter last year.

Senior Notes

In December 2007 the company issued US $600 million second lien eight-year notes (“Senior Notes”) at an issue price of
98.657 for net proceeds of US $575 million after fees and expenses. A portion of the proceeds was used to repay the US $180
million Oil Sands Term Loan, to fully repay drawn amounts and then cancel the company’s conventional oil and gas line of
credit and to fund a one-year interest reserve account in the amount of US $63.6 million. The remainder of the proceeds are
targeted to partially fund the construction of Algar.

To March 31, 2008, the proceeds of the Senior Note financing have been utilized as follows:

As stated at
the time of financing(1) As actually applied
(1)
($000s)
Gross proceeds $576,380 $591,942
Underwriters commissions and issue costs (13,380) (16,493)
Repayment of Oil Sands Term Loan (186,000) (180,000)
Funding interest reserve account (66,000) (63,600)
Repay the conventional line of credit - (2,500)
Net proceeds for the construction of Algar (2) $311,000 $329,349

(1) The Canadian dollar equivalent changed between the dates of announcing and closing the financing due to significant changes in the CDN/US exchange
rates in late 2007.
(2) Net proceeds are available for funding capital expenditures relating to Algar. As at March 31, 2008, approximately $14 million had been spent in respect
of these expenditures.

PROPERTY AND EQUIPMENT ADDITIONS

Property and equipment additions totaled $116 million in the first quarter of 2008 (first quarter 2007 - $110 million). A
breakdown of these additions follows:

Three months ended March 31
($000) 2008 2007
Crude oil, natural gas and oil sands $112,957 $106,794
Refinery expenditures 3,027 3,117
$115,984 $109,881

Oil sands expenditures of $83 million were incurred in the first quarter of 2008 for exploratory core hole drilling, seismic
shooting and processing, some preliminary facility expenditures for Algar and Pod One pre-operating costs in excess of
bitumen revenues which were capitalized. In the first three months of 2008, 128 exploratory core holes were drilled. In the first
quarter of 2007, $86 million was spent to drill 75 exploratory core holes and to shoot and process seismic data.

Conventional oil and gas expenditures of $30 million in the first quarter of 2008 include costs of drilling, completing,
equipping and working over conventional oil and gas wells, undeveloped land acquisition, seismic expenditures and facility
expenditures. In the first quarter of 2008, the company drilled 20 (16.5 net) crude oil and natural gas wells, resulting in 13
(10.5 net) gas wells; one (one net) suspended gas well, three (two net) oil wells; and three (three net) abandoned wells. In the
first quarter of 2007, $20 million was incurred to drill 19 (18 net) oil and gas wells.

OUTLOOK

The company’s business plan anticipates continued growth, with stronger production revenue and cash flow as Pod One
achieved commerciality effective March 1, 2008. Emphasis will continue to be placed on delineating and developing more
production projects at Great Divide, while developing the company’s recently-expanded conventional production base and
profitably operating the Montana refinery. Additional financing may be required for future projects at Great Divide,
development of conventional petroleum and natural gas assets and for the Montana refinery, especially if a decision is made to
expand simultaneously and not sequentially.

The company’s first 10,000 bbl/d oil sands project, Pod One, was completed on schedule in 2007. Fourteen of the fifteen
horizontal well pairs are presently producing in excess of 7,000 bbl/d. It is anticipated that the targeted bitumen production
volume of 10,000 bbl/d will be achieved in 2008.

The company’s second project, Algar, is expected to commence a 10-month period of construction in the second half of 2008,
following receipt of the necessary governmental regulatory approvals. Algar’s design is similar to that of Pod One and its
construction timetable is expected to be comparable. Production from Algar is anticipated to commence in late 2009 or early
2010 and, following ramp up, to add an additional 10,000 bbl/d to Connacher’s growing production base. The cost of Algar is
budgeted at $326 million, as it incorporates scope changes and increased infrastructure costs relative to Pod One. The cost of
the Algar project was fully funded in December 2007.

Additional 10,000 bbl/d oil sands projects (Pods) are anticipated, subject to confirmation of definitive additional reserves and
resources. The timing of additional Pods is dependent on a number of factors which are outside of the control of the company,
including the regulatory process.

Connacher has increased its 2008 firm and contingent capital expenditure budget to $391 million from $373 million to provide
for increased capital outlays on conventional assets, following a successful winter 2008 drilling program, and for oil terminal
and related facilities at Great Divide, with these increases offset by the deferral of some anticipated expenditures at the
Montana refinery.

Information relating to Connacher, including Connacher’s Annual Information Form is on SEDAR at www.sedar.com. See
also the company’s website at www.connacheroil.com.

SIGNIFICANT ACCOUNTING POLICIES AND APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

The significant accounting policies used by the company are described below. Certain accounting policies require that
management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported
amounts of assets, liabilities, revenues and expenses. Changes in these estimates and assumptions may have a material impact
on the company’s financial results and condition. The following discusses such accounting policies and is included herein to
aid the reader in assessing the critical accounting policies and practices of the company and the likelihood of materially
different results being reported. Management reviews its estimates and assumptions regularly. The emergence of new
information and changed circumstances may result in changes to estimates and assumptions which could be material and the
company might realize different results from the application of new accounting standards promulgated, from time to time, by
various regulatory rule-making bodies.

The following assessment of significant accounting polices and critical accounting estimates is not meant to be exhaustive.

Reserve Estimates

Under Canadian Securities Administrators’ “National Instrument 51-101-Standards of Disclosure for Oil and Gas Activities”
(“NI 51-101”) proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. In
accordance with this definition, the level of certainty should result in at least a 90 percent probability that the quantities
actually recovered will exceed the estimated reserves. In the case of probable reserves, which are less certain to be recovered
than proved reserves, NI 51-101 states that it must be equally likely that the actual remaining quantities recovered will be
greater or less than the sum of the estimated proved plus probable reserves. Possible reserves are those reserves less certain to
be recovered than probable reserves. There is at least a 10 percent probability that the quantities actually recovered will exceed
the sum of proved plus probable plus possible reserves.

The company’s oil and gas reserve estimates are made by independent reservoir engineers using all available geological and
reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a
result of changes in prices, costs, fiscal regimes, reservoir performance or a change in the company’s plans. The reserve
estimates can also be used in determining the company’s borrowing base for its credit facilities and may impact the same upon
revision or changes to the reserve estimates. The effect of changes in reserve estimates on the financial results and financial
position of the company is described below.

Full Cost Accounting for Oil and Gas Activities

The company uses the full cost method of accounting for exploration and development activities. In accordance with this
method of accounting, all costs associated with exploration and development are capitalized whether successful or not. The
aggregate of net capitalized costs and estimated future development costs is depleted using the unit-of-production method
based on estimated proved reserves. A change in estimated total proved reserves could significantly affect the company’s
calculation of depletion.

Major Development Projects and Unproved Properties

Certain costs related to acquiring and evaluating unproved properties are excluded from net capitalized costs subject to
depletion until proved reserves have been determined or their value is impaired. Costs associated with major development
projects are not depleted until commencement of commercial operations. All capitalized costs are reviewed quarterly and any
impairment is transferred to the costs being depleted or, if the properties are located in a cost centre where there is no reserve
base, the impairment is charged directly to income.

All costs related to the Great Divide oil sands project are being capitalized to specific projects, or “Pods”, pending
commencement of commercial operations from each Pod. Upon commencement of commercial operations of a Pod, the related
capital costs and estimates of future capital requirements for such Pod will be added to the company’s depletable costs and
depleted under the unit-of-production method based on the company’s total proved reserves. Effective March 1, 2008, the
company’s first oil sands project, Pod One, was declared commercially operative and its related costs were added to the
company’s depletable cost pool.

Ceiling Test

The company is required to review the carrying value of all property, plant, and equipment, including the carrying value of its
conventional and its commercially operative oil sands properties, for potential impairment. Impairment is indicated if the
carrying value of the long-lived asset or oil and gas cost centre is not recoverable by the future undiscounted cash flows. If
impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the long-lived asset is
charged to earnings.

The ceiling test is based on estimates of reserves prepared by qualified independent evaluators, production rate, crude oil,
bitumen and natural gas prices, future costs and other relevant assumptions. By their nature, reserve estimates are subject to
measurement uncertainty and the impact of ceiling test calculations on the consolidated financial statements of changes to
reserve estimates could be material.

Asset Retirement Obligations

The company is required to provide for future removal and site restoration costs by estimating these costs in accordance with
existing laws, contracts or other policies. These estimated costs are charged to earnings and the appropriate liability account
over the expected service life of the asset. When the future removal and site restoration costs cannot be reasonably determined,
a contingent liability may exist. Contingent liabilities are charged to earnings only when management is able to determine the
amount and the likelihood of the future obligation. The company estimates future retirement costs based on current costs as
estimated by the company’s engineers, adjusted for inflation and credit risk. These estimates are subject to measurement
uncertainty.

Legal, Environmental Remediation and Other Contingent Matters

In respect of these matters, the company is required to determine whether a loss is probable, based on judgment and
interpretation of laws and regulations and also to determine if such a loss can be estimated. When any such loss is determined,
it is charged to earnings. Management continually monitors known and potential contingent matters and makes appropriate
provisions by charges to earnings when warranted by circumstance.

Income Taxes

The company follows the liability method of accounting for income taxes. Under this method, tax assets are recognized when it
is more than likely that realization will occur. Tax liabilities are recognized for temporary differences between recorded book
values and underlying tax values. Rates used to determine income tax asset and liability amounts are enacted tax rates expected
to be used in future periods, when the timing differences reverse. The period in which timing differences reverse is impacted by
future income and capital expenditures. Rates are also affected by legislative changes. These components can impact the charge
for future income taxes.

Stock-Based Compensation

The company uses the fair value method to account for stock options. The determination of the amounts for stock-based
compensation are based on estimates of stock volatility, interest rates and the term of the option. By their nature, these
estimates are subject to measurement uncertainty.

NEW SIGNIFICANT ACCOUNTING POLICIES

As of January 1, 2008, the company adopted new CICA Handbook, Section 3862, “Financial Instruments - Disclosures” and
Section 3863, “Financial Instruments - Presentation” which replaced former Section 3861. The new standards require
disclosure of the significance of financial instruments to an entity’s financial statements, the risks associated with the financial
instruments and how those risks are managed.

As of January 1, 2008, the company also adopted new CICA Handbook Section 1535, “Capital Disclosures” which requires
entities to disclose their objectives, policies and processes for managing capital and, in addition, whether the entity has
complied with any externally imposed capital requirements.

In February 2008, the CICA issued Section 3064, “Goodwill and Intangible Assets”, replacing Section 3062, “Goodwill and
Other Intangible Assets” and Section 3450, “Research and Development Costs.” The new Sections will be applicable to
financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the company will adopt the
new standards for its fiscal year beginning January 1, 2009. Section 3064 establishes standards for the recognition,
measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-
oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062,
and therefore are not anticipated to have a significant impact on the company’s financial statements.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

In January 2006, the Canadian Accounting Standards Board adopted a strategic plan for the direction of accounting standards
in Canada. As part of the plan, Canadian GAAP for public companies will converge with International Financial Reporting
Standards (“IFRS”) over the next few years. The company is currently assessing the impact of the convergence of Canadian
GAAP with IFRS on its financial statements and expects to begin work on the conversion process later in 2008.

RISK FACTORS AND RISK MANAGEMENT

Connacher is exposed to risks and uncertainties inherent in the oil and gas exploration, development, production and refining
industry. A detailed summary of the company’s risks and uncertainties is included in the company’s 2007 Annual Information
Form and in MD&A included in the company’s 2007 annual report, which are available on SEDAR at www.sedar.com and on
the company’s website at www.connacheroil.com.

Some of the more significant risks affecting Connacher’s operating results and financial in the first quarter of 2008 related to
changing commodity prices, which were influenced by a weaker US dollar. The average WTI selling price increased by
approximately 68 percent to $97.90/bbl in the first quarter of 2008. Additionally, the heavy oil : light oil pricing differential
narrowed. These two factors were the main reasons that refining margins shrank from 19 percent in the first quarter of 2007 to
one percent in the first quarter of 2008. However, these two factors had a positive impact on pricing the company’s first quarter
bitumen and crude oil revenues, reflecting the benefit of the company’s integrated business model.

DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the company is
accumulated, recorded, processed, summarized and reported to the company’s management as appropriate to allow timely
decisions regarding required disclosure. The company’s Chief Executive Officer and Chief Financial Officer have concluded,
based on their evaluation as of the end of the period covered by this MD&A, that the company’s disclosure controls and
procedures as of the end of such period are effective to provide reasonable assurance that material information related to the
company, including its consolidated subsidiaries, is communicated to them as appropriate to allow timely decisions regarding
required disclosure.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of the company is responsible for designing adequate internal controls over the company’s financial reporting to
provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with Canadian GAAP. There have been no changes in the company’s systems of internal
control over financial reporting that would materially affect, or is reasonably likely to materially affect, the company’s internal
controls over financial reporting.

It should be noted that while the company’s Chief Executive Officer and Chief Financial Officer believe that the company’s
disclosure controls and procedures provide a reasonable level of assurance that they are effective and that the internal controls
over financial reporting are adequately designed, they do not expect that the financial disclosure controls and procedures or
internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or
operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In reaching a
reasonable level of assurance, management necessarily is required to apply its judgment in evaluating the cost-benefit
relationship of possible controls and procedures.

QUARTERLY RESULTS
Fluctuations in results over the previous eight quarters are due principally to variations in oil and gas prices and
production/sales volumes.

2006 2007 2008
Three Months Ended
Financial Highlights ($000 except per share amounts) – Unaudited
Revenues 61,239 103,110 76,700 65,923 93,266 101,991 83,340 100,656
Cash flow(1) 9,499 14,957 14,015 10,980 16,876 10,025 7,084 7,825
Basic, per share (1) 0.05 0.08 0.08 0.06 0.09 0.05 0.03 0.04
Diluted, per share (1) 0.05 0.08 0.07 0.05 0.08 0.05 0.03 0.03
Net earnings (loss) (2,419) 6,771 3,267 4,984 22,228 14,589 (840) (1,833)
Basic and diluted per share (0.01) 0.03 0.02 0.03 0.11 0.07 0.00 (0.01)
Property and equipment additions 34,280 41,449 74,960 109,881 93,223 64,006 55,852 115,984
Cash on hand 7,505 14,450 142,391 66,209 25,375 754 392,271 323,423
Working capital surplus (deficiency) (42,483) (39,942) 118,626 24,027 36,320 (19,853) 389,789 287,105
Debt 70,365 62,380 229,254 207,828 272,559 260,606 664,462 671,014
Shareholders’ equity 340,639 378,730 385,398 384,593 417,793 428,764 480,439 471,559
Operating Highlights
Daily production / sales volumes
Natural gas - mcf/d 15,172 12,711 11,291 9,665 9,017 9,413 8,889 10,493
Bitumen - bbl/d (2) - - - - - - - 1,773
Crude oil - bbl/d 1,026 1,059 1,139 905 731 781 752 996
Equivalent - boe/d (3) 3,554 3,177 3,021 2,515 2,234 2,350 2,233 4,518
Product pricing
Crude oil - $/bbl 61.45 62.53 46.65 49.09 49.79 55.98 56.79 79.50
Bitumen - $/bbl (2) - - - - - - - 53.01
Natural gas - $/mcf 5.66 5.33 6.57 7.76 7.02 4.70 5.82 6.94
Selected Highlights - $/boe (3)
Weighted average sales price 41.88 42.16 42.15 47.48 44.63 37.43 42.29 54.46
Royalties 10.43 10.72 9.00 11.22 3.23 6.32 6.34 7.45
Operating costs 7.63 7.99 9.27 8.54 13.08 9.00 13.77 14.32
Netback (4) 23.82 23.45 23.88 27.72 28.32 22.11 22.18 32.69
Refining throughput
Crude charged (bbl/d) 6,864 9,613 9,642 9,621 9,248 9,400 9,610 9,830
Refining utilization (%) 83 101 102 101 97 100 101 104
Margins (%) 8 16 15 19 21 15 6 1
Common Share Information
Shares outstanding at end of period (000) 191,924 197,878 197,894 198,218 198,834 199,447 209,971 210,277
Weighted average shares outstanding for the period
Basic (000) 191,672 193,587 193,884 198,119 198,360 198,539 204,701 210,234
Diluted (000) 198,931 200,572 204,028 200,008 209,088 210,580 220,362 231,510
Volume traded during quarter (000) 80,347 48,849 46,444 55,292 61,162 70,939 52,198 63,718
Common share price ($)
High 5.05 4.55 4.43 4.13 4.43 4.40 4.08 3.94
Low 3.10 3.09 3.17 3.07 3.07 3.20 3.31 2.59
Close (end of period) 4.30 3.60 3.49 3.86 3.69 4.01 3.79 3.13

(1) Cash flow and cash flow per share do not have standardized meanings prescribed by Canadian generally accepted accounting principles (“GAAP”) and
therefore may not be comparable to similar measures used by other companies. Cash flow is calculated before changes in non-cash working capital,
pension funding and asset retirement expenditures. The most comparable measure calculated in accordance with GAAP would be net earnings. Cash flow
is reconciled with net earnings on the Consolidated Statement of Cash Flows and in the accompanying Management Discussion & Analysis. Management
uses these non-GAAP measurements for its own performance measures and to provide its shareholders and investors with a measurement of the
company’s efficiency and its ability to internally fund future growth expenditures.
(2) The recognition of bitumen sales from Great Divide Pod One commenced March 1, 2008, when it was declared ‘commercial’. Prior thereto, all operating
costs, net of revenues, were capitalized.
(3) All references to barrels of oil equivalent (boe) are calculated on the basis of 6 mcf : 1 bbl. Boes may be misleading, particularly if used in isolation. This
conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the
wellhead.
(4) Netback is a non-GAAP measure used by management as a measure of operating efficiency and profitability. It is calculated as crude oil, bitumen and
natural gas revenue less royalties and operating costs. Netbacks are reconciled to net earnings in the accompanying MD&A.

Connacher Oil and Gas Limited
CONSOLIDATED BALANCE SHEETS
(Unaudited)

($000) March31,2008 December31,2007

ASSETS
CURRENT
Cash $257,489 $329,110
Restricted cash (Note 9(c)) 65,934 63,161
Accounts receivable 52,581 25,084
Inventories (Note 5) 38,033 18,379
Income taxes recoverable 4,867 4,279
Prepaid expenses 1,528 2,520
Due from Petrolifera 7 -
420,439 442,533

Property and equipment 782,725 671,422
Goodwill 103,676 103,676
Investment in Petrolifera 36,023 35,610
Deferred costs 5,235 5,587
$1,348,098 $1,258,828
LIABILITIES
CURRENT
Accounts payable and accrued liabilities $133,334 $52,744
133,334 52,744

Long term debt (Note 4(e)) 671,014 664,462
Future income taxes 48,081 36,818
Asset retirement obligations (Note 6) 23,995 24,365
Employee future benefits 115 -
876,539 778,389

SHAREHOLDERS’ EQUITY
Share capital, contributed surplus and equity component (Note 7) 433,530 444,086
Retained earnings 48,156 49,989
Accumulated other comprehensive loss (10,127) (13,636)
471,559 480,439
$1,348,098 $1,258,828


Connacher Oil and Gas Limited
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
Three Months Ended March 31
(Unaudited)

($000, except per share amounts) 2008 2007
REVENUES
Upstream, net of royalties $27,926 $8,207
Downstream 71,899 57,596
Interest and other income 831 120
100,656 65,923

EXPENSES
Upstream - diluent purchases and operating costs 13,992 1,932
Upstream transportation costs 494 -
Downstream – crude oil purchases and operating costs (Note 5) 71,393 46,398
General and administrative 3,066 3,584
Stock-based compensation (Note 7(a)) 1,516 2,946
Finance charges 4,431 446
Foreign exchange loss (gain) 1,892 (1,702)
Depletion, depreciation and accretion 7,464 7,357
104,248 60,961

Earnings (loss) before income taxes and other items (3,592) 4,962

Current income tax provision 817 2,713
Future income tax provision (recovery) (2,163) 1,165
(1,346) 3,878

Earnings (loss) before other items (2,246) 1,084

Equity interest in Petrolifera earnings 413 3,900

NET EARNINGS (LOSS) (1,833) 4,984

RETAINED EARNINGS, BEGINNING OF PERIOD 49,989 9,028

RETAINED EARNINGS, END OF PERIOD $48,156 $14,012

EARNINGS PER SHARE (Note 9 (a))
Basic $(0.01) $0.03
Diluted $(0.01) $0.03


Connacher Oil and Gas Limited
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended March 31
(Unaudited)

($000) 2008 2007
Net earnings (loss) $(1,833) $4,984
Foreign currency translation adjustment 3,509 (561)
Comprehensive income $1,676 $4,423






CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE LOSS
Three Months Ended March 31
(Unaudited)

($000) 2008 2007
Balance, beginning of period $(13,636) $(130)
Foreign currency translation adjustment 3,509 (561)
Balance, end of period $(10,127) $(691)



Connacher Oil and Gas Limited
CONSOLIDATED STATEMENTS OF CASH FLOW
Three Months Ended March 31
(Unaudited)

($000) 2008 2007

Cash provided by (used in) the following activities:

OPERATING
Net earnings (loss) $(1,833) $4,984
Items not involving cash:
Depletion, depreciation and accretion 7,464 7,357
Stock-based compensation 1,516 2,946
Finance charges – non cash portion 1,249 -
Employee future benefits 113 130
Future income tax provision (recovery) (2,163) 1,165
Foreign exchange loss (gain) 1,892 (1,702)
Equity interest in Petrolifera earnings (413) (3,900)
Cash flow from operations before working capital and other changes 7,825 10,980
Asset retirement expenditures (123) -
Changes in non-cash working capital (Note 9(b)) 21,770 6,922
29,472 17,902

FINANCING
Issue of common shares, net of share issue costs (Note 7) 17 280
Increase in bank debt - 27,600
Repayment of bank debt - (9,000)
Deferred financing costs (82) -
(65) 18,880

INVESTING
Acquisition and development of oil and gas properties (114,055) (105,294)
(Increase) decrease in restricted cash (2,773) 56,579
Change in non-cash working capital (Note 9(b)) 12,400 (7,105)
(104,428) (55,820)

NET DECREASE IN CASH (75,021) (19,038)

Impact of foreign exchange on foreign currency denominated cash 3,400 (565)

CASH, BEGINNING OF PERIOD 329,110 19,603

CASH, END OF PERIOD $257,489 $-

Supplementary information – Note 9



Connacher Oil and Gas Limited
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Period ended March 31, 2008
(Unaudited)

1. FINANCIAL STATEMENT PRESENTATION

The Consolidated Financial Statements include the accounts of Connacher Oil and Gas Limited and its subsidiaries
(collectively “Connacher” or the “company”) and are presented in accordance with Canadian generally accepted accounting
principles. Operating in Canada, and in the U.S. through its subsidiary, Montana Refining Company, Inc. (“MRCI”), the
company is in the business of exploring, developing, producing, refining and marketing crude oil, bitumen and natural gas.

2. SIGNIFICANT ACCOUNTING POLICIES

The interim Consolidated Financial Statements have been prepared following the same accounting policies and methods of
computation as indicated in the annual audited Consolidated Financial Statements for the year ended December 31, 2007,
except as described in Note 3. The disclosures provided below do not conform in all respects to those included with the annual
audited Consolidated Financial Statements. The interim Consolidated Financial Statements should be read in conjunction with
the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2007.

3. NEW ACCOUNTING STANDARDS
Effective January 1, 2008, the company adopted new CICA Handbook, Section 3862, “Financial Instruments - Disclosures”
and Section 3863, “Financial Instruments - Presentation” which replaced former Section 3861. The new standards require
disclosure of the significance of financial instruments to an entity’s financial statements, the risks associated with the financial
instruments and how those risks are managed.

As of January 1, 2008, the company also adopted new CICA Handbook Section 1535, “Capital Disclosures” which requires
entities to disclose their objectives, policies and processes for managing capital and, in addition, whether the entity has
complied with any externally imposed capital requirements.

In February 2008, the CICA issued Section 3064, “Goodwill and Intangible Assets,” replacing Section 3062, “Goodwill and
Other Intangible Assets” and Section 3450, “Research and Development Costs,” applicable to financial statements relating to
fiscal years beginning on or after October 1, 2008. The company will adopt the new standards for its fiscal year beginning
January 1, 2009. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill
subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are
unchanged from the standards included in the previous Section 3062, and therefore are not anticipated to have a significant
impact on the company’s financial statements.

4. FINANCIAL INSTRUMENTS AND CAPITAL RISK MANAGEMENT

The company is exposed to financial risks on a range of financial instruments including its cash, accounts receivable and
payable, amounts due from/to Petrolifera, its Revolving Credit Facilities, the Convertible Debentures, the Senior Notes, the
cross currency swap and the natural gas costless collar. The company is also exposed to risks in the way it finances its capital
requirements. The company manages these financial and capital structure risks by operating in a manner that minimizes its
exposures to volatility of the company’s financial performance. These risks affecting the company are discussed below. No
significant changes have occurred in either the company’s risk exposure or its risk management strategy in the current period.

(a) Credit risk

Credit risk is the risk that a contracting entity will not fulfill its obligations under a financial instrument and cause a financial
loss to the company. To help manage this risk, the company has a policy for establishing credit limits, requiring collateral
before extending credit to customers where appropriate and monitoring outstanding accounts receivable. The majority of the
company’s financial assets arise from the sale of crude oil, bitumen, natural gas and refined products to a number of large
integrated oil companies and product retailers and are subject to normal industry credit risks. The fair value of accounts
receivable and accounts payable are represented by their carrying values due to the relatively short periods to maturity of these
instruments. The maximum exposure to credit risk is represented by the carrying amount on the consolidated balance sheet.
The company regularly assesses its financial assets for impairment losses. There are no material financial assets that the
company considers past due or any allowances for uncollectible accounts.

(b) Market risk

Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in
market prices. The company is exposed to market risk as a result of potential changes in the market prices of its crude oil,
bitumen, natural gas and refined product sales volumes.

A portion of this risk is mitigated by Connacher’s integrated business model. The cost of purchasing natural gas for use in its
oil sands and refinery operations is offset by the company’s monthly conventional natural gas sales; and the majority of the
company’s monthly bitumen sales is offset by its monthly purchases of heavy crude oil required for processing at its refinery.
Petroleum commodity futures contracts, price swaps and collars may be utilized to reduce exposure to price fluctuations
associated with the sales of additional natural gas and crude oil sales volumes and for the sale of refined products.

As part of the company’s risk management strategy, a natural gas costless collar contract has been put in place effective for the
period April 1 to October 31, 2008. The collar has a floor price of US $7.50/mmbtu and a ceiling price of US $10.05/mmbtu on
a notional volume of 5,000 mmbtu per day of natural gas sales. The intent of this natural gas pricing collar was not to speculate
on future natural gas prices, but rather to protect the downside risk to the company’s cash flow and the lending value of its
assets, which is considered very important during a period of rapid growth with significant capital expenditures. The risk in
implementing the collar is that future natural gas prices could escalate beyond the ceiling price, limiting the company’s natural
gas revenue. As at March 31, 2008 the carrying value of this contract was adjusted to its calculated fair value and resulted in a
reduction of Upstream Revenues and an accrued liability of $816,000. A $0.50 per mcf decrease in natural gas prices would
have resulted in an increase in earnings of $200,000 and a $0.50 per mcf increase in natural gas prices would have resulted in a
decrease in earnings of $227,000 due to the sensitivity of the natural gas collar at March 31, 2008 as determined by an option
pricing model.

(c) Interest rate risk

Interest rate risk refers to the risk that the fair value or future cash flows of a financial instrument will fluctuate because of
changes in market interest rates. The fair values of the company’s cross-currency and interest rate swaps are influenced by
changes in interest rates. A 25 basis point change in interest rates would result in approximately a $1.9 million change in the
fair value of the company’s cross-currency and interest rate swaps.

(d) Currency risk

Currency risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in
foreign exchange rates.

As Connacher incurs the majority of its expenditures in Canadian dollars, it is exposed to the impact of fluctuations in the
US/Canadian dollar exchange rate on pricing of its sales of crude oil and bitumen (which are generally priced by reference to
US dollars but settled in Canadian dollars) and for the translation of its US refining operating results and its US dollar
denominated Senior Notes to Canadian dollars for financial statement reporting purposes.

In order to mitigate half of the foreign exchange exposure on the Senior Notes, the company entered into a cross currency swap
to fix one half of the Senior Notes’ principal and interest payments in Canadian dollars. The swaps provide for a fixed payment
of C$304.8 million in exchange for receipt of US $300 million on December 15, 2015. The swaps also provide for semi-annual
interest payments commencing June 15, 2009 until December 15, 2015 at a fixed rate of 10.795 percent based on a notional
C$304.8 million of debt in exchange for receipt of semi-annual interest payments until December 15, 2015 at a fixed rate of
10.25 percent based on a notional US $300 million of debt.

Relative to the company’s crude oil revenue receivables, Senior Notes and currency swap, a $0.01 strengthening in the
Canadian dollar exchange rate would have resulted in a $4.2 million increase in net earnings for the first quarter of 2008, and a
$0.01 weakening of the Canadian dollar would have resulted in a $2.3 million decrease in net earnings in the first quarter of
2008.

(e) Liquidity risk

Liquidity risk is the risk that the company will not have sufficient funds to repay its debts and fulfill its financial obligations.

To manage this risk, the company follows a conservative financing philosophy, pre-funds major development projects,
continuously monitors expenditures against pre-approved budgets to control costs, regularly monitors its operating cash flow,
working capital and bank balances against its business plan, maintains accessible revolving banking lines of credit, and
maintains prudent insurance programs to minimize exposure to insurable losses.

Additionally, the long term nature of the company’s debt repayment obligations is aligned to the long term nature of its assets.
The Convertible Debentures do not mature until June 30, 2012, unless converted to common shares earlier, and principal
repayments are not required on the Senior Notes until their maturity date of December 15, 2015. This affords Connacher the
opportunity to deploy its conventional, oil sands, and refinery cash flow to fund the development of further expansion projects
over the next few years without having to make principal payments or raise new capital unless expenditures exceed cash flow
and credit capacity.

The Revolving Credit Facilities (C $150 million and US $50 million) provide liquidity as the company has the ability to draw
on them when, and if, necessary anytime over their five year term. As at March 31, 2008 they secure approximately $19
million of issued letters of credit.

Substantially, all of the company’s assets (except its investment in Petrolifera) secure the Revolving Credit Facilities and
Senior Notes.

The company is subject to financial covenants with respect to its Revolving Credit Facilities and Senior Notes. The financial
covenants applicable to the first quarter of 2008 are:

• Consolidated Total Debt to Total Capitalization Ratio shall not exceed 65% at the end of the fiscal quarter. Consolidated
Total Debt includes all debt of the company except for the Convertible Debentures. Total Capitalization is the sum of
Consolidated Total Debt, the principal amount of the Convertible Debentures and the book value of Shareholders’ Equity.

• Consolidated Senior Debt to EBITDA Ratio shall not exceed 3.5:1 at the end of any fiscal quarter, as determined on a
rolling four fiscal quarter basis. Consolidated Senior Debt includes all borrowings under the Revolving Credit Facilities.
EBITDA is equal to Net Earnings plus finance charges, taxes, depletion, depreciation, accretion, stock based compensation
expense and earnings of Petrolifera accounted for on an equity basis, with further adjustment made for extraordinary gains
or losses and other non cash items added or deducted in determining Net Earnings.

The company is in compliance with all of its financial covenants.

The change in carrying value of long-term debt at March 31, 2008 ($671 million) from December 31, 2007 ($664 million) is
primarily due to the change in the Canadian : US exchange rate in converting the US dollar-denominated Senior Notes to
Canadian dollars and accretion of the debt discount of approximately $1.2 million.

At March 31, 2008 the fair values of the Convertible Debentures and Senior Notes were $93 million and $602 million,
respectively, based on their quoted market prices. The fair value of the cross-currency and interest rate swaps was an asset of
$2.2 million, based on the present value of future cash flows.

The company’s term debt is repayable as follows:
• Convertible Debentures - June 30, 2012 in the amount of $100,050,000, unless converted into common shares prior
thereto; and
• Senior Notes - December 15, 2015 in the amount of US$600 million.

Connacher’s investment in Petrolifera also provides liquidity. Trading on the TSX, Connacher’s 13.1 million shares held in
Petrolifera are readily marketable as they have not been collateralized. Although it is not Connacher’s intention to sell these
shares in the foreseeable future, the shareholding provides Connacher an additional margin of safety.

(f) Capital risks

Connacher’s objectives in managing its cash, debt and equity (“capital”), its capital structure and its future capital requirements
are to safeguard its ability to meet its financial obligations, to maintain a flexible capital structure that allows multiple
financing options when a financing need arises and to optimize its use of short-term and long-term debt and equity at an
appropriate level of risk.

The company manages its capital structure and follows a financial strategy that considers economic/industry conditions, the
risk characteristics of its underlying assets and its growth opportunities. It strives to continuously improve its credit rating and
reduce its cost of capital. Connacher monitors its capital using a number of financial ratios and industry metrics to ensure its
objectives are being met and to ensure continued compliance with its debt covenants.


Connacher’s current capital structure and certain financial ratios are noted below.
As at
March 31, 2008
As at
December 31, 2007
($000)
Long term debt (1) $671,014 $664,462
Shareholders’ equity
Share capital, contributed surplus and equity component 433,530 444,086
Accumulated other comprehensive loss (10,127) (13,636)
Retained earnings 48,156 49,989
Total $1,142,573 $1,144,901

Debt to book capitalization (2) 59% 58%
Debt to market capitalization (3) 49% 44%
(1) Long-term debt is stated at its carrying value, which is net of fair value adjustments, original issue discounts, transaction costs and the Convertible
Debentures’ equity component value.
(2) Calculated as long-term debt divided by the book value of shareholders’ equity plus long-term debt.
(3) Calculated as long-term debt divided by the period end market value of shareholders’ equity plus long-term debt.

Connacher currently has a high ratio of debt to capitalization, and its debt service costs are high relative to cash flow. This is
due to pre-funding the full cost of Algar, the company’s second oil sands project, in December 2007, by issuing US$600
million of Senior Notes. As at March 31, 2008, the company’s net debt (long-term debt, net cash on hand) was $347,591. Net
debt to book capitalization was 30 percent and net debt to market capitalization was 25 percent.

5. INVENTORIES

Inventories consist of the following:

($000) March 31, 2008 December 31, 2007
Crude oil $3,218 $2,258
Other raw materials and unfinished products (1) 1,385 1,501
Refined products (2) 29,785 11,183
Process chemicals (3) 789 1,036
Repairs and maintenance supplies and other (4) 2,856 2,401
$38,033 $18,379

(1) Other raw materials and unfinished products include feedstocks and blendstocks, other than crude oil. The inventory carrying value includes the costs of
the raw materials and transportation.
(2) Refined products include gasoline, jet fuels, diesels, asphalts, liquid petroleum gases and residual fuels. The inventory carrying value includes the cost of
raw materials, transportation and direct production costs.
(3) Process chemicals include catalysts, additives and other chemicals. The inventory carrying value includes the cost of the purchased chemicals and related
freight.
(4) Repair and maintenance supplies in crude refining and oil sands supplies.

In accordance with the company’s accounting policies, inventories are valued at the lower of cost and net realizable value. At
each of December 31, 2007 and March 31, 2008 net realizable value was used to value asphalt inventories as at each date net
realizable value was lower than cost. At March 31, 2008 the net realizable value of asphalt was higher than it was at December
31, 2007, due to seasonal influences on asphalt selling prices. As a result, asphalt inventory values at March 31, 2008 increased
due to increases in market prices from December 31, 2007 by approximately $8 million.

Included in downstream crude oil purchases and operating costs for the three months ended March 31, 2008 was approximately
$64 million of inventory costs.
6. ASSET RETIREMENT OBLIGATIONS

The following table reconciles the beginning and ending aggregate carrying amount of the obligation associated with the
company’s retirement of its oil sands and conventional petroleum and natural gas properties and facilities.

($000)
Three months ended
March 31, 2008 Year ended
December 31, 2007
Asset retirement obligations, beginning of period $24,365 $7,322
Liabilities incurred 547 8,277
Liabilities settled (123) (311)
Change in estimated future cash flows (1,216) 7,503
Accretion expense 422 1,574
Asset retirement obligations, end of period $23,995 $24,365

Liabilities incurred in 2008 have been estimated using a discount rate of 10 percent reflecting the company’s credit-adjusted
risk free interest rate given its current capital structure and an inflation rate of two percent. The company has not recorded an
asset retirement obligation for the Montana refinery as it is currently the company’s intent to maintain and upgrade the refinery
so that it will be operational for the foreseeable future. Consequently, it is not possible at the present time to estimate a date or
range of dates for settlement of any asset retirement obligation related to the refinery.


7. SHARE CAPITAL AND CONTRIBUTED SURPLUS

Authorized
The authorized share capital comprises the following:

• Unlimited number of common voting shares
• Unlimited number of first preferred shares
• Unlimited number of second preferred shares

Issued

Only common shares have been issued by the company.
Number
of Shares Amount
($000)

Balance, Share Capital, December 31, 2007 209,971,257 $406,881
Issued upon exercise of options in 2008 (a) 197,000 95
Issued to directors under share award plan (b) 108,975 381
Assigned value of options exercised in 2008 - 35
Share issue costs, net of income taxes (51)
Tax effect of expenditures renounced pursuant to the issuance of flow
through common shares in 2007 (c) (13,250)
Balance, Share Capital, March 31, 2008 210,277,232 $394,091

Balance, Contributed Surplus, December 31, 2007 $20,382
Stock based compensation for share options expensed in 2008 2,269
Assigned value of options exercised in 2008 (35)
Balance, Contributed Surplus, March 31, 2008 $22,616
Equity component of Convertible Debentures, December 31, 2007 and
March 31, 2008 $16,823

Total Share Capital, Contributed Surplus and Equity Component
December 31, 2007 $444,086
March 31, 2008 $433,530

(a) Stock Options

A summary of the company’s outstanding stock options, as at March 31, 2008 and 2007 and changes during those periods is
presented below:
For the three months ended March 31 2008 2007
Number of
Options Weighted Average
Exercise Price Number of
Options Weighted Average
Exercise Price
Outstanding, beginning of period 17,432,717 $3.60 16,212,490 $3.31
Granted 2,548,023 $3.15 2,744,833 3.88
Exercised (197,000) $0.53 (324,433) 0.89
Expired (14,000) $3.51 (213,000) 3.75
Outstanding, end of period 19,769,740 $3.57 18,419,890 $3.44
Exercisable, end of period 13,693,864 $3.54 9,617,198 $3.02

All stock options have been granted for a period of five years. Options granted under the plan are generally fully exercisable
after either two or three years. The table below summarizes unexercised stock options.
Range of Exercise Prices

Number
Outstanding

Weighted Average
Remaining Contractual Life
at March 31, 2008
$0.20 - $0.99 1,800,968 1.6
$1.00 - $1.99 1,632,000 2.2
$2.00 - $3.99 9,013,239 3.9
$4.00 - $5.56 7,323,533 3.1
19,769,740 3.3

During the first quarter of 2008 a non-cash charge of $1.5 million (2007 - $2.9 million) was expensed, reflecting the fair value
of stock options amortized over the vesting period. A further $798,000 (2007 - $546,000) was capitalized to property and
equipment.

The fair value of each stock option granted is estimated on the date of grant using the Black-Scholes option-pricing model with
weighted average assumptions for grants as follows:

For the three months ended March 31 2008 2007
Risk free interest rate 3.2% 4.5%
Expected option life (years) 3 3
Expected volatility 48% 68%

The weighted average fair value at the date of grant of all options granted in the first quarter of 2008 was $1.12 per option
(2007 - $1.86).

(b) Share award plan for non-employee directors

On January 16, 2008, 108,975 shares were issued to non-employee directors under the share award plan, settling the accrued
liability of $381,000 relating to this award.

On March 25, 2008 an additional 283,730 shares were awarded to non-employee directors over a future vesting period. A total
of 392,705 share awards were outstanding at March 31, 2008 and vest on the following dates:



December 31, 2008 5,210
January 1, 2009 108,975
December 31, 2009 5,210
January 1, 2010 136,655
January 1, 2011 136,655
392,705
In the first quarter of 2008, a non-cash charge of $45,000 (2007 – nil) was accrued as a liability and expensed in respect of
shares yet to be issued under the share award plan.

(c) Flow through shares

Effective December 31, 2007, the company renounced $52.25 million of resource expenditures to flow-through share investors.
The related tax effect of $13.25 million of these expenditures was recorded in 2008. The company has incurred all of the
required expenditures related to these flow-through shares in 2007 and 2008.

8. SEGMENTED INFORMATION

The company has changed its segmentation in 2008 to better reflect the organization of its business by combing the former
Canadian administrative segment with the Canadian oil and gas segment. In Canada, the company is in the business of
exploring for and producing crude oil, natural gas and bitumen. In the U.S., the company is in the business of refining and
marketing petroleum products. The significant aspects of these operating segments are presented below. Comparative figures
have been reclassified.

Three months ended March 31 Canada USA
($000) Oil and Gas Refining Total
2008
Revenues, net of royalties $27,926 $71,899 $99,825
Equity interest in Petrolifera earnings 413 - 413
Interest and other income 706 125 831
Crude oil purchases and operating costs 14,486 71,393 85,879
General and administrative 3,066 - 3,066
Stock-based compensation 1,516 - 1,516
Finance charges 4,372 59 4,431
Foreign exchange (gain) 1,960 (68) 1,892
Depletion, depreciation and accretion 6,216 1,248 7,464
Tax provision (recovery) (702) (644) (1,346)
Net earnings (loss) (1,869) 36 (1,833)
Property and equipment, net 724,575 58,150 782,725
Capital expenditures 112,957 3,027 115,984
Total assets $1,214,329 $133,769 $1,348,098
2007
Revenues, net of royalties $8,207 $57,596 $65,803
Equity interest in Petrolifera earnings 3,900 - 3,900
Interest and other income 13 107 120
Crude oil purchases and operating costs 1,932 46,398 48,330
General and administrative 3,584 - 3,584
Stock-based compensation 2,946 - 2,946
Finance charges 371 75 446
Foreign exchange (gain) (1,702) - (1,702)
Depletion, depreciation and accretion 6,100 1,257 7,357
Tax provision 224 3,654 3,878
Net earnings (loss) (343) 5,327 4,984
Property and equipment, net 435,526 51,495 487,021
Capital expenditures 106,764 3,117 109,881
Total assets $646,870 $110,335 $757,205

9. SUPPLEMENTARY INFORMATION

(a) Per share amounts

The following table summarizes the common shares used in earnings per share calculations.

For the three months ended March 31 (000) 2008 2007
Weighted average common shares outstanding 210,234 198,119
Dilutive effect of stock options - 1,889
Weighted average common shares outstanding – diluted 210,234 200,008

(b) Net change in non-cash working capital

For the three months ended March 31 ($000) 2008 2007
Accounts receivable $(27,497) $(182)
Inventories (19,654) (14,558)
Due from Petrolifera (7) 109
Prepaid expenses 992 366
Accounts payable and accrued liabilities 80,924 14,589
Income taxes payable/recoverable (588) (507)
Total $34,170 $(183)

Summary of working capital changes:

($000) 2008 2007
Operations $21,770 $6,922
Investing 12,400 (7,105)
$34,170 $(183)

(c) Supplementary cash flow information

For the three months ended March 31 2008 2007
($000)
Interest paid $383 $5,759
Income taxes paid 1,127 3,039
Stock-based compensation capitalized $798 $546
At March 31, 2008 cash of $65.9 million (December 31, 2007 - $63.2 million) was restricted to fund the first year of interest
payments on the Senior Notes.



(d) Defined benefit pension plan
In the first quarter of 2008, $113,000 (2007 - $130,000) has been charged to expense in relation to MRCI’s defined benefit
pension plan.